90 results about "Displacement pressure" patented technology

The invention discloses a method for evaluating the crude oil utilization rate during shale oil in-situ heating modification exploitation, and is applied to the field of oil development. The method comprises the following steps: (1) constructing a three-dimensional grid model of shale oil reservoirs between two horizontal wells, and determining parameters such as initial temperature, initial fluid pressure, initial porosity, initial oil saturation, initial gas saturation, initial water saturation and initial dissolved gas volume of three-dimensional grid units of each reservoir; (2) determining the pressure of each reservoir three-dimensional grid unit when the fluid pressure is balanced according to the shale oil layer section bottom hole pressure and the reservoir displacement pressure gradient; (3) according to the characteristics of a temperature field, a pressure field and the like of the in-situ heating shale oil reservoir, obtaining three-dimensional grid unit temperature and instantaneous fluid pressure parameters of each reservoir, and determining porosity and fluid saturation at each time point; and (4) according to the instantaneous fluid pressure and the balanced fluid pressure of the three-dimensional grid unit of each reservoir, determining the oil, gas and water production quantity and the production rate of the grid unit of each reservoir in combination with the oil, gas and water saturation.

The invention discloses a method and a system for characterizing a miscible state after action of CO2 and crude oil based on interfacial tension, and relates to the technical field of oil reservoir CO2 flooding development, the method comprises the following steps: S1, obtaining a relation curve of oil displacement efficiency and displacement pressure through a numerical simulation tubule experiment, and determining the minimum miscible pressure; s2, obtaining a relation curve of interfacial tension and displacement pressure through a numerical simulation tubule experiment, and determining critical interfacial tension; s3, on the basis of the minimum miscible pressure and the critical interfacial tension, key parameters representing the miscible state are determined; and S4, carrying out engineering characterization on the miscible state after the CO2 and the crude oil act on the basis of the key parameters for characterizing the miscible state. According to the method, the miscible state is divided according to the interfacial tension, the miscible state in the CO2 flooding process is further refined, errors caused by the fact that the miscible state is judged due to the fact that the minimum miscible pressure changes along with mining time are reduced, and the miscible state in the CO2 flooding development process is represented more finely.

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 provides a method for testing fracture flow capacity under a shale oil core stress condition. The method comprises the following steps: forming a fracture on a core; carrying out vacuumizing and high-pressure saturated oil treatment on the rock core subjected to fracture forming; according to the core crack type, a plurality of net effective stress points are increased by changing the displacement pressure difference and the confining pressure, and then core outlet end flow data are obtained; a copper foil is utilized to support the crack, different crack opening degrees are simulated, a plurality of net effective stress points are added, flow data of the outlet end of the core are obtained, and shale core flow capacity evaluation under the condition of different crack opening degrees is achieved; after different flowing pressure differences are selected to achieve stable flowing, corresponding flowing data are obtained, and the liquid-phase permeability of the fractured rock core is calculated according to a Darcy formula; and evaluating the flow capacity of the rock core according to result data, comprehensive stress conditions and fracture forms. According to the invention, different fracture forms can be simulated, so that the experimental research is more comprehensive, and a reference is provided for the crude oil flowing capacity of fractured reservoirs in shale oil development at present.

The invention relates to the technical field of unconventional oil-gas exploration, in particular to a high-clay shale oil in-situ accumulation dynamics mechanism and mode evaluation method. The method comprises the following steps: collecting fluid pressure, temperature data, displacement pressure, oiliness, brittleness index, hydrostatic pressure, vitrinite reflectivity and density value of a shale sample at each depth position point of an exploratory well of each exploration point; calculating abnormal sensitivity; further acquiring ground temperature evaluation credibility; obtaining a self-adaptive fitting weight; acquiring the actual fluid pressure of the exploratory well of each survey point at each depth; acquiring the pressure coefficient of the shale sample at each depth position point of the exploratory well of each survey point; obtaining a self-sealing reservoir forming mode and a retention reservoir forming mode of shale oil; based on the vitrinite reflectivity, the oiliness, the brittleness index and the pressure coefficient, a shale oil enrichment area evaluation comprehensive index is constructed, and the in-situ flow of the high-clay shale is evaluated. According to the method, the accuracy of in-situ self-sealing reservoir formation, retention reservoir formation and dynamic mechanism evaluation of the high-clay shale is improved.

Disclosed in the present application are a method for determining the fault sealing capacity of CO2 geological storage, and a related apparatus. The method specifically comprises: determining whether the lithology of a caprock corresponding to a reservoir consisting of CO2 satisfies preset conditions, the preset conditions comprising that the lithology is shale, and the proportion of clay minerals satisfies a preset range; when the lithology of the caprock does not satisfy the preset conditions, calculating a displacement pressure difference between the reservoir and a fault formed between the caprock and the reservoir; and when the displacement pressure difference is not greater than zero, determining a caprock thickness, a reservoir thickness and a fault displacement on the basis of a fault profile diagram; and, on the basis of a numerical value sorting relationship of the caprock thickness, the reservoir thickness and the fault displacement, determining the fault sealing capacity of CO2 geological storage, the fault sealing capacity comprising: a fault being completely sealed, a fault being partially sealed and a fault being unsealed. Therefore, the present application finally determines the fault sealing capacity of the CO2 geological storage.

The invention belongs to the technical field of shale oil and gas development, discloses a system and a method for determining a multi-criterion displacement phase diagram for nanopores, and can solve the problem that the multi-criterion displacement phase diagram for the nanopores cannot be determined in the prior art. The visual imaging assembly is used for recording an image of the invasion phase fluid displacing the displaced phase fluid in the nano-porous medium, and the calculation assembly is used for obtaining the displacement mode and the average flow velocity under different displacement pressure difference conditions, obtaining the viscosity ratio and the capillary number, mapping the viscosity ratio and the capillary number into a double logarithmic coordinate system in a data point form, and fitting to obtain a multi-criterion displacement phase diagram. The system can effectively control and monitor fluid flow for the nanofluidic chip, assist in observing a displacement mode in a two-phase flow process, and obtain a multi-criterion displacement phase diagram of nanopores. The method for determining the multi-criterion displacement phase diagram for the nanopores, disclosed by the invention, has the same advantages as the system.

The invention belongs to the technical field of petroleum and natural gas development, and particularly relates to a visual reservoir core relative permeability high-precision measuring device and method based on an unsteady state method. The device comprises a clamp holder, three glass tubes, a flow drum, a water metering pump, a gas-liquid separation tube, an annular pressure pump, a gas cylinder, an annular pressure sensor, a pressure regulating valve and an injection pressure sensor. The holder comprises a support, a barrel, a pull rod nut assembly, an adjusting screw rod, a restraint frame, an inlet plug, two pressing caps, a baffle ring, a sealing ring, a rock core cone, a transparent rubber sleeve and an outlet plug. The method comprises the following steps: 1, core pretreatment; 2, carrying out liquid measurement on the permeability; 3, displacement pressure is determined; 4, calculating the pore volume of the rock core; and 5, gas-driven water test and dynamic permeability calculation. The problems that reservoir rock core relative permeability measuring equipment is complex, inaccurate and difficult to use, and the stress state of the rock core is not comprehensively simulated are solved.

The invention discloses an excavator impact load calculation method which comprises the following steps: firstly, collecting the displacement and pressure of an oil cylinder of a working device of an excavator in a dynamic state, calculating and testing the actually measured oil cylinder force at an impact moment, and establishing a theoretical dynamic mathematical model; according to the established theoretical dynamic mathematical model, motion coordinates of a twisting point and a bucket tooth are calculated, and according to the motion coordinates and the gravity load of the excavator in the motion process, the theoretical mathematical model oil cylinder force of the working device is calculated by inputting assumed bucket tooth stress data; and finally, comparing the oil cylinder force of the theoretical mathematical model with the actually measured oil cylinder force at the impact moment to obtain an accurate impact load. The invention further provides a system for calculating the impact load of the excavator. The problems that in the prior art, special equipment needs to be used for excavation impact load testing, and testing data are different are solved. The impact load can be extracted more accurately only by collecting the pressure and displacement of the oil cylinder and considering the inertial load in the movement process.

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 heat supply pipeline pressure testing device, and particularly relates to the technical field of pipeline pressure testing, which comprises a pressure testing ring, two transverse rubber rings, a heat supply pipeline, a first pressure sensor and transverse and longitudinal interval pressure testing mechanisms, the transverse and longitudinal interval pressure test mechanism comprises a support frame, a bidirectional screw and a gear motor, and further comprises a pressure test area positioning mechanism and a displacement pressure test detection assembly. According to the invention, through the transverse and longitudinal spaced pressure test mechanisms, a left side cavity area and a right side cavity area are formed in the pressure test ring, so that a specific area of pressure test fault leakage of the heat supply pipeline can be accurately known, and the pressure test accuracy of the heat supply pipeline is greatly improved; therefore, the problem that the pressure testing accuracy of the heat supply pipeline is poor due to the fact that it is difficult to accurately know the specific leakage positions of the specified transverse area and the longitudinal interval area of the heat supply pipeline and it is difficult to accurately know the pressure failure leakage problem area is solved.

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 invention discloses a low-pressure low-permeability oil layer alternate injection reverse self-displacement pressure flooding method and system, and relates to the technical field of petroleum reservoir transformation and yield increase, and the method comprises the steps that an oil flooding system is injected into a low-pressure low-permeability oil layer until the formation pressure coefficient of the low-pressure low-permeability oil layer rises to a first preset threshold value; high-viscosity fracturing fluid is injected into the low-pressure and low-permeability oil layer until the fracturing crack length of the low-pressure and low-permeability oil layer is increased to a second preset threshold value; an oil displacement system and high-viscosity fracturing fluid are alternately injected into the low-pressure and low-permeability oil layer until the formation pressure coefficient rises to a third preset threshold value and the fracturing fracture length increases to a fourth preset threshold value; and the soaking time is determined based on the geological parameters of the low-pressure and low-permeability oil layer and the total amount of injected liquid, and soaking is conducted on the production well of the low-pressure and low-permeability oil layer based on the soaking time. The technical problem that the yield stabilizing effect is not ideal in the prior art is solved.

The present application discloses a method for determining the fault sealing property of CO2 geological storage and a related device, specifically determining whether the lithology of the cap rock corresponding to the reservoir composed of CO2 meets preset conditions, the preset conditions including that the lithology is shale and the proportion of clay minerals meets a preset range; when the lithology of the cap rock does not meet the preset conditions, calculating the difference in displacement pressure between the fault formed between the cap rock and the reservoir and the reservoir; when the difference in displacement pressure is not greater than zero, determining the cap rock thickness, reservoir thickness and fault throw based on the fault profile, and determining the fault sealing property of CO2 geological storage based on the numerical ranking relationship of the cap rock thickness, reservoir thickness and fault throw, the fault sealing property includes: complete fault sealing, partial fault sealing and no fault sealing, and finally determining the fault sealing property of CO2 geological storage.

The invention discloses a method and a device for testing the starting pressure gradient of weakly cemented argillaceous siltstone. The method comprises the following steps: putting the weakly cemented argillaceous siltstone into a core holder, vacuumizing the core holder and the weakly cemented argillaceous siltstone in the core holder, and saturating formation water; setting initial confining pressure, and pressurizing the core holder for multiple times until no liquid is discharged from the outlet end of the core holder; carrying out displacement tests on the displacement fluid according to the sequentially increasing speed of the pump speed, timing each displacement test, and recording the displacement pressure of the core holder, the confining pressure change and the displacement fluid capacity; converting into variable pressure displacement, performing a displacement test on the change of the core holder according to a displacement pressure regulation and control process, and recording the displacement pressure, the confining pressure change and the displacement fluid capacity of the core holder; sequentially increasing the confining pressure, and repeating the displacement test until no displacement fluid exists at the outlet end of the core holder; the invention designs a method for testing the water phase starting pressure gradient of the sandstone core under the conditions of normal temperature and normal pressure.

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 relates to an experimental device and method for measuring gas-water relative permeability of hydrate-containing sediments by an unsteady-state method, xenon is used for replacing methane gas to synthesize xenon hydrate, then methane gas is used for displacing water, in the displacement process, the displacement pressure is kept between the balance pressure of the xenon hydrate and the balance pressure of the methane hydrate, and the gas-water relative permeability of the hydrate-containing sediments is measured. Therefore, the saturation of the xenon hydrate in the measurement process is not changed, and no new methane hydrate is generated. The response rule of the gas and water relative permeability of the hydrate-containing sediment along with the saturation of the hydrate is quantitatively described through an unsteady state method, and the gas and water relative permeability of the hydrate-containing sediment can be measured under the indoor condition.

The invention belongs to the technical field of oilfield exploitation, and particularly relates to a method for determining a conglomerate oil reservoir gel-carbon dioxide alternate displacement critical pressure gradient. The problem that the alternate displacement efficiency and sweep efficiency are low due to the fact that the gel-carbon dioxide alternate displacement pressure gradient of the conglomerate oil reservoir is unreasonable at present is solved. According to the technical scheme, the method comprises the steps that a large-scale physical model is established, gel-carbon dioxide is preferably selected as an alternate displacement medium, well periphery plane oil saturation change values under different displacement pressure gradients are obtained, and alternate displacement efficiency and sweep efficiency under the different displacement pressure gradients are calculated according to the well periphery plane oil saturation change values; displacement pressure gradient, sweep efficiency and alternate displacement efficiency charts are established, and in different stages of actual production, alternate displacement critical pressure gradients of the conglomerate oil reservoir in the first 500 days and the last 500 days can be determined according to the two charts; the new method provided by the invention can provide a scientific basis for practical application, reduce the operation cost and improve the oil reservoir exploitation benefit.

The present invention relates to a method for characterizing the sealing performance of mudstone caprock considering sandstone interlayers, and the method is as follows: Step 1: Identify all sandstone interlayers in the caprock from the logging curves of regional production wells, and number the mudstone caprock sections and sandstone interlayer sections separately from bottom to top; Step 2: Read the average acoustic travel time and thickness h<subgt;ij< / subgt; corresponding to each sandstone interlayer section, and calculate the displacement pressure P<subgt;ij< / subgt> of each sandstone interlayer section respectively; Step 3: Segmentally fit the acoustic travel time curve of each mudstone caprock section, calculate the average acoustic travel time and thickness h<subgt;ck< / subgt> of each mudstone caprock section, and calculate the displacement pressure P<subgt;ck< / subgt> of each mudstone caprock section respectively; Step 4: Calculate the overall displacement pressure P of the caprock; In the process of evaluating the sealing property of the mudstone caprock, the present invention takes into account the actual geological conditions of the sandstone interlayers developed in the mudstone caprock. On the other hand, it is simpler and more convenient to characterize the sealing performance of the mudstone caprock considering sandstone interlayers by the present invention.

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 oil and gas field development, in particular to a method for calculating the wettability reversal degree of tight sandstone, which comprises the following steps: acquiring the before-soaking spontaneous imbibition time, before-soaking spontaneous imbibition amount, soaking precursor pressure difference and soaking precursor amount of a tight sandstone core sample before being soaked in a silicon dioxide nanofluid; obtaining the spontaneous imbibition time after soaking, the spontaneous imbibition amount after soaking, the displacement pressure difference after soaking and the displacement amount after soaking after the tight sandstone core sample is soaked in the silicon dioxide nanofluid; and the wettability inversion degree is obtained on the basis of obtaining the spontaneous imbibition weight and the displacement weight. According to the method for calculating the wettability reversal degree of the tight sandstone, quantitative evaluation of wettability reversal can be achieved only by relying on results obtained by a spontaneous imbibition experiment and a displacement experiment without damaging a rock core, theoretical reference is provided for improving the recovery ratio of a tight sandstone gas reservoir, and the method has important value for achieving efficient development.

A method for determining the critical physical properties of natural gas injection into tight reservoirs within overpressure zones. First, convert the mercury injection displacement pressure value of the reservoir into the gas-water displacement pressure value during the gas drive water process under geological temperature and pressure conditions, and establish the gas-water displacement pressure distribution profile during the gas drive injection process of the tight reservoir. Then, determine the natural gas accumulation time and the paleo-burial depth of the corresponding strata. Next, select sandstone samples rich in gas inclusions under a polarizing microscope to determine the paleo-pressure and residual pressure of the strata during the natural gas accumulation period. Then, determine the paleo-pressure structure of the strata. In a single overpressure system, construct a trend line of the residual pressure change gradient, that is, the effective injection power trend line. Finally, superimpose the effective injection power trend line on the converted gas-water displacement pressure distribution profile to divide the distribution intervals of effective injection and ineffective injection reservoir samples, and determine the critical physical property limit value of natural gas injection into tight reservoirs within overpressure zones. The present invention realizes the quantitative evaluation of the effectiveness of natural gas injection into deep overpressure tight reservoirs.

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 quantitative evaluation method and device for displacement pressure evolution of clastic rock, and the method comprises the steps: firstly constructing a reservoir pore evolution model according to the original porosity, the surface porosity and the burial evolution history; then, according to the reservoir pore evolution model, establishing a cover layer pore attenuation model; through a mercury injection experiment and porosity analysis regression, establishing a function relationship between the displacement pressure and the porosity as well as between the displacement pressure and the buried depth; according to the statistical displacement pressure and porosity, determining a breakthrough pressure limit between reservoir and cap layers and a limit buried depth of pore response; and finally, based on the function relationship, according to the porosity evolution process and the burial history, inverting the displacement pressure of the cover layer, and obtaining a dynamic evolution curve of the displacement pressure. According to the method, a pore evolution and burial evolution constraint mechanism is introduced, simulation from static parameter analysis to dynamic process is realized, a basis is provided for quantitative analysis of displacement pressure evolution and effectiveness evaluation of a cover layer, and a basis is also provided for a space-time configuration relationship of oil and gas accumulation elements.

The present invention provides a method for determining the relative permeability of oil and water and a dynamic characterization model in the process of infiltration regulation and oil recovery. The method for determining the relative permeability of oil and water includes: constructing a capillary bundle geometric model; respectively determining the initial contact angle, final contact angle and oil-water interfacial tension of each capillary in the capillary bundle geometric model during the flow simulation process; constructing a contact angle constitutive model that reflects the change in rock wettability during the process of infiltration regulation and oil recovery, so as to constrain the size of each capillary contact angle in the capillary bundle geometric model during the flow simulation process; based on the initial contact angle, final contact angle, oil-water interfacial tension and contact angle constitutive model of each capillary in the capillary bundle geometric model during the flow simulation process, using the capillary bundle geometric model, step-by-step controlling the displacement pressure difference to perform multiple rounds of flow simulation, and obtaining the oil-water relative permeability curves at different stages in the process of infiltration regulation and oil recovery; wherein the flow simulation is a displacement flow simulation or a suction flow simulation.

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.