46 results about "Displacement pressure" patented technology

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 relates to the technical field of shale oil exploitation, in particular to a shale oil working fluid displacement device and a reservoir physical property evaluation method. In the shale oil working fluid displacement process, dynamic pressure difference time sequence data corresponding to all moments are obtained, and due to the fact that the viscosity and flow characteristic difference of different fluid media is large, dynamic pressure difference fluctuation is remarkable during displacement; determining the fidelity of the displacement pressure at each moment by analyzing the frequency domain and linear regression characteristics; thirdly, all moments are clustered based on the dynamic pressure difference and the displacement pressure fidelity, and the moments in the same displacement state are clustered into one class; in view of the fact that fixed PID parameters are difficult to adapt to different working fluid medium characteristics and can cause control delay, in a cluster to which the current moment belongs, moment distribution characteristics and dynamic pressure difference time sequence data dynamic estimation characteristics are analyzed, the pressure instability degree and the observation uncertainty are reflected, a preset gain coefficient is adjusted accordingly, more accurate PID control is achieved, and the control precision is improved. And the reliability of subsequent reservoir physical property evaluation is ensured.

The invention discloses a quantitative prediction method for water logging of a well section of an infilled horizontal well of an offshore water-drive oil field. The method comprises the following steps: S1, dividing a well spacing area of the horizontal well into a plurality of grids; s2, establishing a displacement pressure, gravity and buoyancy coupled flooding thickness quantitative prediction mathematical model, and drawing a waterline propulsion chart; s3, based on the waterline propelling condition, the remaining oil distribution coefficient of the well spacing area is calculated; s4, screening remaining oil gathering grids according to the remaining oil distribution coefficient, and quantitatively judging the water logging condition of the well section of the horizontal well; and S5, reevaluating the enrichment degree of the remaining oil, and further evaluating and determining the potential tapping grid of the horizontal well. According to the quantitative prediction method for flooding of the well section of the infilled horizontal well in the offshore water-drive oil field, three-dimensional representation of the flooding position and the flooding degree of the well section of the infilled horizontal well in a high-water-content oil reservoir can be achieved, the remaining oil enrichment area suitable for implementing the horizontal well can be accurately screened and evaluated, then well position deployment of the horizontal well is guided, and the infilled adjustment effect is improved.

The application discloses a method for determining a reasonable displacement pressure of liquid carbon dioxide phase change displacement of coal seam gas, and specifically comprises the following steps: S1, performing an isothermal adsorption experiment on a coal sample of a target coal seam; S2, respectively calculating virtual saturated vapor pressures of CO2 and CH4 gas; S3, establishing a relationship between gas adsorption potential and gas adsorption equilibrium pressure; S4, respectively calculating densities of CO2 and CH4; S5, respectively calculating adsorption spaces of CO2 and CH4 in a coal body; S6, establishing a relationship formula between adsorption potentials of the two kinds of gas and the adsorption spaces; S7, determining a reasonable displacement pressure; S8, determining a reasonable displacement pressure; S9, calculating a CO2 percolation coefficient; S10, determining a reasonable percolation pressure; and S11, determining a reasonable injection pressure. The method provides scientific guidance for popularization and application of the liquid CO2 phase change displacement technology of CH4 in a coal seam.

The invention belongs to the technical field of reservoir engineering application, and discloses a digital-analog characterization method for reservoir pressure drive seepage parameters, which comprises the following steps: S1, measuring the permeability and relative permeability of a stratum sample before pressure drive, manufacturing artificial microfractures in a reservoir, converting original stratum pore seepage into artificial fracture net seepage, and calculating the permeability of the stratum sample before pressure drive; performing a water injection experiment on the sample by adopting different displacement pressure gradients, and determining the change relation of the permeability of the reservoir sample along with the pressure and the change condition of relative permeability before and after the matrix fracture pressure is reached in the water injection experiment process; s2, calculating the limit wave and radius under the pressure-driven water injection condition; and S3, carrying out digital-analog characterization on the oil reservoir pressure-drive water injection seepage parameters. According to the method, the permeability and relative permeability parameters are adjusted in real time by using the pressure as a reference condition, and full-life-cycle seepage parameter characterization in the pressure driving process is equivalently completed.

The invention discloses a method and a system for analyzing a petroleum secondary migration mode. Comprising the following steps: carrying out an indoor physical experiment on to-be-evaluated petroleum to obtain a capillary number index for representing a competitive characteristic between capillary pressure and viscous force and a Bo number index for representing a competitive characteristic between buoyancy and capillary pressure in a secondary migration process of the to-be-evaluated petroleum; according to the ratio of the capillary number index to the Bo number index, determining the main power type of the to-be-evaluated petroleum by using a preset displacement pressure and buoyancy control migration mode identification chart; and determining the fluid secondary migration mode of the to-be-evaluated petroleum according to the main power type. According to the invention, the petroleum secondary migration law under different geological conditions can be analyzed.

The invention provides a compact low-permeability reservoir fracturing well pattern gas drive effect prediction method and system, and relates to the technical field of gas drive effect prediction. The method comprises the following steps: firstly, determining basic geometric parameters of a rhombic inverted nine-point well pattern of a target block and fracturing design parameters to be optimized; and constructing a well pattern embedded into the main fracture and a fracture parameterized model, and reflecting a coupling relationship between the fracture and matrix flow. A training sample is generated through experimental design, rapid flow simulation is conducted through a parameterized model, and space collaboration quantitative indexes such as a gas shortest breakthrough time index, an effective wave and coefficient correction factor and a displacement pressure gradient strengthening factor are calculated. Performing extended production dynamic simulation on part of samples to obtain key indexes such as accumulative oil production and accumulative gas-oil ratio, and training a machine learning agent model; and with maximization of the cumulative oil production and the gas shortest breakthrough time index and control of the cumulative gas-oil ratio as optimization objectives, a multi-objective optimization algorithm is adopted to obtain a Pareto optimal solution set, and a final recommendation scheme is screened out.

The invention relates to an evaluation method of a broken basin volcanic rock reservoir, and belongs to the technical field of physical exploration. Determining the parameter value of the lower limit of the reservoir through the relationship between the pore throat radius distribution and the mercury injection displacement pressure; constructing a geologic function related to the porosity, the gas saturation and the permeability; and integrating the reservoir average pore throat radius, the comprehensive evaluation parameters, the porosity and the permeability, and establishing a reservoir comprehensive grading evaluation standard. Based on well drilling logging data and seismic data, a geological basis is provided for work such as evaluation, exploration and development deployment of a favorable area of the volcanic gas reservoir.

The invention relates to the technical field of rock physical analysis in oil-gas exploration and development, and particularly provides a shale full-size pore structure characterization method which comprises the following steps: acquiring high-pressure mercury injection experimental data and nuclear magnetic resonance experimental data of a shale sample, dividing a pore system of the shale sample into a small pore section and a large pore section by an inflection point of fractal dimension, respectively fitting the pore throat radius of the small pore section and the pore throat radius of the large pore section with the transverse relaxation time to obtain two groups of conversion coefficients, respectively inverting the pore diameter distribution curve of the small pore section and the pore diameter distribution curve of the large pore section by utilizing the two groups of conversion coefficients, and carrying out segmented integration according to the intersection point of the two curves to characterize the full pore diameter distribution of the shale sample. According to the method, a fractal inflection point division pore system is introduced, deep structure information is excavated by utilizing a fractal theory, segmentation fitting is carried out, and the technical problems that a traditional HPMI-NMR conjoint analysis method is insufficient in precision under the conditions of large displacement pressure, low mercury injection saturation and strong heterogeneity are solved.

The invention discloses a method, a device and equipment for evaluating the oil-gas vertical sealing capability of a fault-damaged cover strata, and the method comprises the steps: carrying out the horizon interpretation and fault interpretation according to the three-dimensional seismic data and the drilled data of a research area; performing time-depth conversion on the obtained horizon data of the target reservoir and the cover layer and the fault data of the target oil source fracture, and constructing a depth domain three-dimensional geologic model and a shale content model in combination with drilled data; determining the compaction diagenesis starting time of fault rocks; determining a fault inclination angle at each preset measuring point, a current burial depth of a position where a cover layer is broken by a fault and a current burial depth of a target reservoir; the surrounding rock deposition time of the target reservoir is determined; the fault rock compaction diagenesis depth is determined; reading the shale content of the target reservoir and the shale content of the fault at each preset measuring point; target reservoir displacement pressure values and fault rock displacement pressure values at the corresponding measuring points are obtained through calculation; and determining an oil-gas vertical sealing capability evaluation result of the cover layer damaged by the fault at the corresponding preset measuring point.

The invention provides a displacement-pressure double-closed-loop control-based intelligent pressure stabilizing system for an outer-steel inner-film gas holder and the gas holder. The system comprises a controller, a displacement detection module, a pressure detection module and a pressure stabilizing execution module, by monitoring the displacement amount and the internal pressure of the inner membrane in real time, the controller adopts a double-closed-loop control algorithm to cooperatively drive the air blower and the pressure release valve, and precise pressure stabilization is achieved; the gas storage cabinet adopts an outer-steel inner-film structure, a pressure regulating chamber of 1-2m is formed between the gas storage cabinet and the outer-steel inner-film structure, and the operating pressure can reach 4-10kPa; the double-membrane gas holder has the cost advantage of a double-membrane gas holder and the characteristics of high pressure and large capacity of a steel gas holder, the defects of response lag and low control precision of a traditional gas holder are overcome through intelligent control, meanwhile, the problems of low pressure, membrane permeation, membrane damage and the like of the double-membrane gas holder are solved, and an efficient and reliable solution is provided for industrial gas storage.

The invention discloses a quantitative evaluation method and device for the three-dimensional fault plugging property of seismic phased modeling, and the method comprises the steps: extracting the fault shale content in fault attributes to a fault surface in a three-dimensional attribute body model based on the three-dimensional attribute body model constructed in a research area, so as to determine the fault mud ratio of the fault surface; determining the fault permeability based on the fault mud ratio and the fault displacement of the fault; the fault conductivity is determined based on the average stratum permeability, the fault permeability, the center distance between grids in the three-dimensional attribute body model and the thickness of a fault zone; constructing fault displacement pressure of the research area based on the fault shale content, the breakpoint burial depth and the fault inclination angle; and based on the fault permeability, the fault conductivity, the fault displacement pressure and the effective seepage area of the fault, constructing a three-dimensional fault plugging performance evaluation factor so as to perform quantitative evaluation on the three-dimensional fault plugging performance. According to the method, the fault plugging performance can be comprehensively and quantitatively evaluated, and meanwhile, the dependence of a well-free area on well data is overcome.

The invention discloses an automatic section forming control method and system during section cutting and underground tunneling equipment, and relates to the technical field of tunneling equipment, and the automatic section forming control method during section cutting comprises the following steps: obtaining system parameters and target displacement; acquiring real-time sensing information; carrying out constant-pressure self-adaptive control on the cutting head; carrying out displacement-pressure cascade closed-loop control on the cutting oil cylinder; and pressure ring control is conducted, specifically, the target pressure Ptarget and the actual oil cylinder pressure P2 are input into a third PID controller, and the third PID controller outputs a control signal Ucyl for controlling the opening degree of a valve port of a multi-way valve of a cutting oil cylinder. The cutting efficiency and the forming quality can be guaranteed at the same time.

The invention provides an optimal selection method for a measure well of a heavy oil viscosity reduction flooding huff-puff guiding effect technology. The optimal selection method for the measure well of the heavy oil viscosity reduction flooding huff-puff guiding effect technology comprises the steps that 1, the sweep range r of a viscosity reduction system is calculated according to oil reservoir parameters and injection parameters; 2, establishing a target block driving pressure gradient regression formula; 3, calculating the driving pressure Pr required by the sweep area; 4, the water well driving pressure PWat is calculated; 5, the oil reservoir range r1 which can be affected by the water injection displacement pressure of the area not affected by the viscosity reduction system is calculated; and 6, according to the relation between the total distance r + r1 capable of being driven by the water well and the well spacing L, whether the production well is the measure well or not is judged. According to the optimal selection method for the thickened oil viscosity reduction and flooding huff-puff efficiency guiding process measure well, the influence of the viscosity reducer property, the well pattern and well spacing and the water injection pressure on the oil well productivity is mainly considered, the situation that only viscosity reduction huff-puff is conducted on a low-liquid-volume oil well is avoided, and well selection has the advantages of being high in pertinence and high in accuracy.

The invention provides a temporary plugging particle parameter optimization method for in-crack temporary plugging fracturing and application, and belongs to the field of reservoir yield increase and transformation. The method comprises the following steps: obtaining a plugging crack width and a temporary plugging layer critical permeability required for plugging a target crack; establishing a quantitative relationship among the permeability of the temporary plugging layer, the displacement pressure and the geometric parameters of the particles, and optimizing the particle size and the particle composition of the temporary plugging particles; establishing a temporary plugging layer strength prediction model through a discrete element method, analyzing the influence rule of the particle shape on the temporary plugging layer strength, and optimizing the temporary plugging particle shape; and optimizing the mechanical parameters of the temporary plugging particles based on the optimized particle size, composition and shape of the temporary plugging particles. By regulating and optimizing the performance parameters of the temporary plugging particles, the compactness and strength of the temporary plugging layer can be effectively improved, and the effectiveness of the in-crack temporary plugging diversion fracturing technology can be effectively improved.

The invention belongs to the technical field of oil-gas well stability monitoring, and particularly relates to a simulation monitoring method for oil-gas well stability influenced by mining, which comprises the following steps: arranging a simulation oil-gas well shaft composite structure according to the relative position of an actual production oil-gas well and a coal face, and the structure comprises a protection casing, a production casing and well cementation cement; strain is monitored through a distributed optical fiber sensor, displacement is monitored through a GNSS telemetering station, air tightness is tested through a pressure gauge, and deformation is detected through a caliper. And comprehensively evaluating the stability of the oil and gas well based on comparison of monitoring data and initial strength parameters. According to the invention, the problems of incapability of real-time monitoring and poor early warning performance of a traditional method are solved, and the monitoring precision and the engineering safety are remarkably improved.

The application discloses a method for constructing a relative permeability curve of a power-law non-Newtonian fluid, which comprises the following steps: first, a non-steady-state relative permeability curve displacement experiment device is built; then, rock sample pretreatment, non-Newtonian fluid rheological parameter testing and displacement experiment data acquisition are completed; the outlet water breakthrough time, the cumulative liquid production and the displacement pressure difference of the non-Newtonian fluid when the constant-speed displacement of the non-Newtonian fluid is recorded; after the experimental data is preprocessed, a relative permeability curve model is preset, the water cut is implicitly solved and the derivative is calculated, and the injection pore multiple of the non-Newtonian fluid and the displacement pressure difference are derived; based on the experimental data, the water saturation-water cut and the displacement pressure difference-water saturation relationship are simultaneously fitted through an iterative optimization algorithm, and finally, the coefficients in the relative permeability curve formula are determined, and the relative permeability curve is constructed. The method improves the smoothness and physical rationality of the relative permeability curve of the non-Newtonian fluid, improves the calculation accuracy, and provides a reliable means for analyzing the seepage characteristics of complex fluids.

The present application belongs to the technical field of underground gas storage evaluation, and discloses a kind of evaluation method of gas storage boundary fault sealing property: according to gas storage dynamic and static data, boundary fault is determined, the lowest value of fault argillaceous content at reservoir unit is obtained, argillaceous content-depth-displacement pressure chart is established, the error of diagenetic time is eliminated, and the sealing capacity of gas storage fault is determined according to the sealing property evaluation data of each fault. The evaluation method is simple and feasible, and can quickly obtain relatively accurate fault sealing property parameters, which can provide certain reference for underground gas storage geological evaluation and reservoir capacity parameter design.

The invention provides a longitudinal displacement wave and efficiency testing device and a calculation method for a huge thick oil and gas reservoir. The device comprises an injection system which comprises a displacement pump and a displacement fluid container, and an outlet of the displacement pump is communicated with an inlet of the displacement fluid container; the model system comprises a multi-tube parallel core clamping model, and pressure gauges for calculating displacement pressure are respectively arranged at an inlet and an outlet of the model; the produced liquid detection and treatment system comprises a gas-liquid separation device and a gas collection device, an outlet of the gas-liquid separation device is communicated with an inlet of the gas collection device, and the gas-liquid separation device is used for detecting produced oil quantity and produced gas quantity; wherein the multi-tube parallel core clamping model is used for simulating longitudinal formation distribution and simulating permeability heterogeneity and fluid heterogeneity of different cores, and the cores in the longitudinal direction are communicated. By means of the device and method, the displacement effect and the displacement sweep efficiency change characteristics of different depths during longitudinal displacement of the huge thick oil reservoir can be known.

The application relates to a method for evaluating the oil recovery rate during in-situ heating and upgrading of shale oil, and is applied to the field of oil development. The method comprises the following steps: 1, constructing a three-dimensional grid model of a shale oil reservoir between two horizontal wells, and determining the initial temperature, initial fluid pressure, initial porosity, initial oil saturation, initial gas saturation, initial water saturation and initial dissolved gas amount of each three-dimensional grid unit of the reservoir; 2, determining the pressure of each three-dimensional grid unit of the reservoir when the fluid pressure is balanced according to the bottom hole pressure of the shale oil layer and the reservoir displacement pressure gradient; 3, obtaining the temperature and instantaneous fluid pressure parameters of each three-dimensional grid unit of the reservoir according to the temperature field and pressure field of the in-situ heating shale oil reservoir, and determining the porosity and fluid saturation at each time point; and 4, determining the oil, gas and water production and recovery rate of each reservoir grid unit according to the instantaneous fluid pressure and balanced fluid pressure of each three-dimensional grid unit of the reservoir, and combining the oil, gas and water saturations.

The application provides a method for determining reasonable displacement pressure difference in thickened oil reservoir viscosity reduction and pressure drive development, comprising the following steps: fitting a relationship between thickened oil mobility and threshold pressure gradient on the basis of experimental results; calculating the mobility value of thickened oil in the reservoir, and calculating the corresponding threshold pressure gradient value according to the relationship; determining the threshold pressure value between injection and production wells according to pressure drive injection-production well spacing, which is taken as the minimum displacement pressure difference; determining the maximum displacement pressure difference through the maximum liquid production capacity of the oil well; calculating the cumulative net present value corresponding to different production pressure differences within the displacement pressure difference limit range; and taking the displacement pressure difference corresponding to the maximum cumulative net present value as the reasonable displacement pressure difference in thickened oil reservoir viscosity reduction and pressure drive development. The method for determining the reasonable displacement pressure difference in thickened oil reservoir viscosity reduction and pressure drive development determines the reasonable displacement pressure difference in thickened oil reservoir viscosity reduction and pressure drive development by using the optimization theory and taking the financial net present value as the optimization target through reservoir numerical simulation and dynamic economic evaluation.

The invention relates to the technical field of oil and gas field development, in particular to a low-permeability reservoir multi-cycle hydraulic fracture expansion method and device and a storage medium. The low-permeability reservoir multi-cycle hydraulic fracture expansion method comprises the steps that the minimum horizontal principal stress and the rock fracture pressure of rock of a target interval are solved; the bottom hole pressure of the target well is obtained; enabling the reservoir to form a shear fracture expansion area; enabling the reservoir to form a tensional fracture expansion area; establishing a high flow guide channel; closing the well, measuring the pressure drop of the well mouth, and waiting for closing of the tensional crack; and the operation from the third step to the sixth step is repeated, multi-cycle liquid injection is conducted, the seam length is increased, and the expansion area of the seam network is expanded. According to the method, a displacement pressure control method is adopted, the reservoir generates shear fractures and tensile fracture zones, the tensile fractures are supported, high flow guide channels are established, the reservoir transformation volume is further increased, the recovery efficiency is improved, the effective period of measures is prolonged by two times compared with conventional fracturing, the construction cost is reduced by 10%, the oil increase of a single well is improved by 15% or above, and low-permeability reservoir benefit development can be achieved.

A carbon dioxide water layer buried geologic body cap rock breakthrough pressure prediction method integrating multi-factor influence belongs to the technical field of carbon dioxide water layer burying, and comprises the following steps: establishing an interfacial tension calculation model considering cap rock temperature and cap rock original pressure influence; establishing a contact angle calculation model considering the influence of the cap layer temperature and the cap layer original pressure; establishing a water film thickness calculation model considering the influence of fluid viscosity, capillary radius and displacement pressure gradient; establishing a cover layer breakthrough pressure calculation model considering the influence of interfacial tension, contact angle and water film thickness; the permeability and porosity are introduced, meanwhile, the CO2 truncation number is introduced, a new calculation model of the cap rock breakthrough pressure is established, and the new calculation model is compared with a test result to verify the accuracy of the established calculation model; and carrying out actual block application on the established new model for the breakthrough pressure of the cap layer. According to the method, the breakthrough pressure of the cap stratum under the reservoir condition can be predicted more truly and accurately, and the method has certain guiding significance for accurately predicting the breakthrough pressure of the cap stratum.

The invention relates to the technical field of electrical equipment monitoring, and discloses an insulating electrical equipment on-line monitoring device, which comprises a transformer and an oil tank arranged at the top of one side of the transformer, and is characterized in that the outer side of the oil tank is in threaded connection with a pressure relief assembly for performing pressure relief on the oil tank; the inner side of the pressure relief assembly is provided with an alarm assembly which generates sound through reciprocating impact, the top of the pressure relief assembly is fixedly provided with a top plate, and the two ends of the top plate are each provided with a pressure sensor in advance; through the linkage design of the pressure relief assembly and the alarm assembly, gradient response to the internal pressure change of the transformer is realized; when a large amount of gas is generated inside due to an insulation fault, the high-pressure gas firstly pushes the movable plate to move upwards, and the main pressure relief channel is opened; in the initial stage of pressure rise or when small pressure fluctuation is caused by non-fault factors such as overheating, gas can directly push the rotating plate through the pressure relief hole to conduct small-displacement pressure relief.

Embodiments of the present application provide a method, device and storage medium for determining the state of reservoir fluid interaction, belonging to the field of reservoir exploration and development. The method for determining the state of reservoir fluid interaction comprises: obtaining the current water saturation and the current CO2 displacement pressure of a target reservoir; and determining the current fluid interaction state of the target reservoir according to the current water saturation and the current CO2 displacement pressure based on a predetermined target correspondence relationship among the water saturation, the CO2 displacement pressure and the state of fluid interaction. The present application can improve the accuracy of the classification result of the state of reservoir fluid interaction.

The application discloses a method for determining relative permeability of loose sandstone gas and water, and comprises the following steps: drying and weighing a rock sample to obtain a dry weight, saturating the rock sample with formation water, applying a set confining pressure to obtain a wet weight, and calculating an effective pore volume of the rock sample; performing a non-steady-state gas displacement water relative permeability determination experiment on the rock sample according to a set displacement pressure difference, obtaining total sand water volume and gas volume change data over time; determining the volume of sand in the produced sand water, determining a water production volume correction coefficient according to the total sand water volume and the volume of sand in the produced sand water, and obtaining net water production volume change data over time; and determining the gas saturation of the rock sample and the gas and water relative permeability change data over time according to the effective pore volume and the net water production volume and gas volume change data over time. The method can obtain more accurate effective pore volume, accurately measure the sand volume, correct the net water production, and improve the accuracy of the determination of the relative permeability of loose sandstone gas and water.

The application provides a method for predicting effectiveness of a shale cap rock over a drilling target of an oil and gas reservoir. The method takes measured displacement pressure of the shale cap rock as a starting point, obtains quantitative threshold thickness data of the shale cap rock according to mutual correlation among burial depth, thickness and sealing property of the shale cap rock through regression and fitting, and then accurately predicts effectiveness of the shale cap rock over the drilling target of the oil and gas reservoir, thereby providing a basis for drilling of the oil and gas reservoir.

The application discloses a weakly cemented argillaceous siltstone starting pressure gradient law analysis method and device, which comprises the following steps: constructing multiple test cores; performing displacement tests on each core holder, timing each displacement test, and recording the displacement pressure, confining pressure change and displacement fluid capacity of the core holder; determining the starting pressure gradient in combination with the confining pressure change of the core holder in each displacement test, determining the real liquid production point of the test core in the displacement test process, and obtaining the minimum starting pressure gradient of each test core; fitting the relationship between the pressure gradient and the liquid production rate to obtain the pseudo starting pressure gradient of each test core; and fitting the relationship between the minimum starting pressure gradient and the pseudo starting pressure gradient and the formation parameters; the application determines the real liquid production point of effective displacement, improves the accuracy of data analysis, and determines the change law of the water phase starting pressure gradient of low-permeability loose argillaceous siltstone with the core seepage characteristics and the properties of formation fluid.

The invention relates to the technical field of carbon capture and storage, in particular to a quantitative characterization method for connectivity of carbon dioxide in a shale cover layer, which comprises the following steps: simulating a formation in-situ environment for the shale cover layer, carrying out a stepped injection pressure displacement test, and collecting transverse relaxation time T2 spectrums under different displacement pressures; and constructing a T2-Pc two-dimensional joint function based on the capillary pressure Pc and the T2 spectrum, and calculating the carbon dioxide phase connectivity coefficient of each pore throat unit in the T2-Pc two-dimensional spectrum. According to the method, a formation in-situ environment is simulated through a multi-field coupling test system, and synchronous acquisition of the occurrence state and the fluidity of the fluid under in-situ stress is realized by combining injection pressure displacement and nuclear magnetic resonance technologies; by constructing a T2-Pc two-dimensional joint map, a pore structure and fluid migration characteristics are synergistically represented, pore throat units which are geometrically communicated but hydraulically isolated are accurately distinguished, a calculation result is remarkably related to microCT test and CO2 phase endpoint relative permeability, and the representation precision is greatly improved.

The invention discloses a method, a device and equipment for evaluating the lateral oil and gas plugging capacity in the active period of a fault. The method comprises the steps of performing horizon interpretation and fault interpretation according to three-dimensional seismic data and drilled data of a research area; performing time-depth conversion on the obtained horizon data of the target reservoir and the fault data of the oil source fracture, and constructing a depth domain three-dimensional geologic model and a shale content model in combination with drilled data; obtaining an oil-gas accumulation period in the research area; obtaining a target oil source fracture matched with the time of the oil-gas accumulation period in the research area; calculating the paleo-burial depth of the target reservoir at each preset measuring point in the oil-gas accumulation period and the paleo-burial depth of the fault in the oil-gas accumulation period; reading the shale content of the target reservoir and the shale content of the fault at each preset measuring point; and comparing the calculated paleo-displacement pressure value of the fault at each preset measuring point with the paleo-displacement pressure value of the target reservoir, and determining the evaluation result of the fault active period lateral oil and gas plugging capacity at the corresponding preset measuring point.