66 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 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.

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 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 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 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.

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 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 provides a method for determining the optimal pressure for converting an oil reservoir into CO2 flooding after water flooding, which comprises the following steps of: carrying out a slim tube displacement experiment to obtain the CO2 flooding recovery ratio of the oil reservoir after water flooding under different displacement pressures and return pressure conditions; and carrying out linear regression on the recovery rates under different displacement pressure and return pressure conditions, and calculating to obtain the CO2-crude oil two-phase minimum miscible phase pressure in the CO2-water-oil three-phase coexistence system. According to the method, the rule that the CO2-water-crude oil three-phase coexistence system has the influence on the CO2-crude oil minimum miscible pressure due to the existence of the water phase under different water contents is determined, and the optimal pressure for CO2 transfer injection development under different water contents is determined, so that the reasonable production pressure during CO2 transfer injection development of an oil reservoir after water drive is adopted in the petroleum industry is guided. According to the method, the optimal pressure of CO2 and crude oil at different water contents can be determined more directly, simply, conveniently and accurately, and scientific and accurate guidance is provided for improving the recovery efficiency and achieving the purpose of increasing yield and efficiency.

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 present invention relates to the technical field of oil and gas field development, and specifically to a method for calculating the degree of wettability reversal of tight sandstone. The method comprises obtaining the spontaneous imbibition time, spontaneous imbibition volume, displacement pressure difference, and displacement volume of a tight sandstone core sample before immersion in a silica nanofluid; obtaining the spontaneous imbibition time, spontaneous imbibition volume, displacement pressure difference, and displacement volume of the tight sandstone core sample after immersion in a silica nanofluid; and then calculating the degree of wettability reversal based on the obtained spontaneous imbibition weight and displacement weight. The present invention establishes a method for calculating the degree of wettability reversal of tight sandstone. The method relies solely on the results obtained from spontaneous imbibition and displacement experiments, and can achieve quantitative evaluation of wettability reversal without destroying the core. This method provides a theoretical reference for improving the recovery rate of tight sandstone gas reservoirs and is of great value for achieving efficient development.

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 present invention discloses a method for characterizing the wettability of reservoir rocks under simulated production conditions, which comprises the following steps: completely saturating a rock sample with a manganese chloride solution and testing the nuclear magnetic resonance T<subgt;1< / subgt>-T<subgt;2< / subgt> spectrum curve of the rock sample; displacing the rock sample with formation crude oil to the irreducible water state, aging it at the formation temperature and then measuring the T<subgt;1< / subgt>-T<subgt;2< / subgt> spectrum curve; conducting waterflooding experiments on the aged rock sample under different simulated production pressure differences respectively and measuring the T<subgt;1< / subgt>-T<subgt;2< / subgt> spectrum curves of the rock sample after each stage of displacement pressure difference; extracting the T<subgt;2 spectrum curves after complete water saturation, irreducible water saturation and each stage of displacement pressure difference; determining the initial wettability of the rock sample according to the shift of the T<subgt;2 spectrum curves between the irreducible water state and the completely water-saturated state; and determining the wettability of the rock sample under each stage of displacement pressure difference according to the shift of the T<subgt;2 spectrum curves after each stage of displacement pressure difference and under complete water saturation. The present invention can determine the wettability of reservoir rocks and its variation characteristics at different production stages, making up for the deficiency that the existing wettability schemes cannot dynamically monitor wettability.