438 results about "Formation water" patented technology

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

A system may include an orienting liner hanger disposed in a main bore of a multilateral well in a position downhole from a junction of the multilateral well. The system may also include a lower completion secured to a downhole end of the orienting liner hanger and a fluid separator assembly disposed uphole from the orienting liner hanger. The fluid separator assembly may be configured to receive formation fluid, which may include oil and water, flowing uphole from the lower completion. The fluid separator assembly may be configured to at least partially separate the formation fluid into formation oil and formation water. The fluid separator assembly may be configured to output formation oil to an upper production tubing and output the formation water into a lateral bore of the multilateral well.

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

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

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

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

The invention provides a calibration method for a nuclear magnetic fluid signal conversion relation with shale as a carrier and application, and belongs to the technical field of unconventional oil-gas exploration and development. The method comprises the steps that shale samples are pretreated, and fluid saturation is conducted on the shale samples; the saturated shale is subjected to centrifugation and drying treatment, and T2 spectrogram testing is carried out by adopting nuclear magnetic resonance equipment in different treatment stages; and the conversion relation of the oil-water fluid in the shale is established by comparing the attenuation amount of the fluid in the shale pores at different stages with the T2 spectrogram signal difference value. The mass change caused by fluid loss in the closed coring shale is used as the verification basis of the conversion relation, and the reliability of the method is ensured. And then crude oil with different maturity degrees and formation water fluids with different mineralization degrees are adopted to repeat the operation, the calibration conversion relation of the crude oil with different maturity degrees and the formation water with different mineralization degrees is obtained, then the change rule of the calibration conversion relation is disclosed, and the accuracy and scientificity of the nuclear magnetic resonance technology in the aspect of shale fluid evaluation are improved.

The invention discloses a high-temperature high-pressure impurity-containing mixed CO2 mineralization reaction device and method.The high-temperature high-pressure impurity-containing mixed CO2 mineralization reaction device comprises a gas supply module, a gas mixer, a mixed gas analysis module, a mineralization reactor, a vacuumizing module and a tail gas treatment module, the gas supply module is used for providing CO2 gas and impurity gas, and the gas mixer is used for mixing the CO2 gas and the impurity gas; the mixed gas analysis module is used for judging whether CO2 gas and impurity gas are uniformly mixed or not, the mineralization reactor is used for simulating a mineralization reaction of a rock sample to be mineralized under the condition of the impurity CO2-containing mixed gas and environment simulation liquid, the vacuumizing module is used for vacuumizing the mineralization reactor, and the tail gas treatment module is used for treating tail gas generated by the mineralization reaction. The device capable of simulating the formation water vapor evaporation environment is developed, so that natural conditions can be reproduced more truly in an experiment, the performance of mineralization reaction under actual geological conditions can be better understood, and the research practicability is improved.

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

The invention relates to the technical field of exploration and development of unconventional oil and gas reservoirs, in particular to an experimental device and method for quantitatively evaluating CO2-hydrocarbon-water interaction mixing and dissolving capacity of a water-containing gas reservoir. The experimental device comprises a vacuum pump, a constant-temperature air bath box, a sample preparation unit, an injection unit, a testing unit and a metering unit. The method comprises the following steps: injecting excessive pure CH4 into a sample preparation unit at a constant pressure, enabling a two-phase system of the pure CH4 and formation water to reach hydrocarbon-water phase balance, transferring the formation water of saturated hydrocarbon into a visual phase tester, injecting CO2 into the visual phase tester at a constant pressure, fully stirring fluid, standing for a period of time, carrying out ion chromatography analysis, and determining the content of CO2 in the formation water. According to the experimental device, the proportion of CO2 and the proportion of CH4 in undissolved gas are determined, an experiment is carried out through the experimental device, a CO2-hydrocarbon-water interaction miscibility theory system in the whole CO2 injection and burying process of the gas reservoir with water can be perfected, and the problem that the miscibility of CO2-CH4 in the CO2-hydrocarbon-water system under the high-temperature and high-pressure conditions is difficult to effectively and quantitatively evaluate is effectively solved.

A fluid separator system may include a separator housing, a turbine chamber formed within the separator housing, and a fluid inlet configured to receive formation fluid and direct the formation fluid into the turbine chamber. The formation fluid may include oil and water. The fluid separator system may also include a turbine disposed within the turbine chamber and configured to rotate to at least partially separate the formation fluid into formation oil and formation water. Additionally, the fluid separator system may include an oil outlet configured to receive the formation oil separated from the formation fluid and direct the formation oil toward an upper production tubing and a water outlet configured to receive the formation water separated from the formation fluid and direct the formation water out of the separator housing.

The invention discloses a wellbore integrity casing damage simulation and repair experimental device, which comprises a heating temperature control box, the interior of the heating temperature control box is divided into an upper part and a lower part, the upper part forms a first cavity for accommodating liquid, and the lower part forms a second cavity for placing a casing damage simulation module or a cement column damage simulation module; the liquid injection and pressurization equipment is communicated with the first cavity and is used for injecting a plugging agent or formation water into the first cavity and pressurizing the plugging agent or the formation water so as to drive the plugging agent or the formation water to enter the casing damage simulation module or the cement column damage simulation module; and the ball valve is arranged at the bottom of the heating temperature control box, is communicated with the second cavity and is used for controlling opening and closing of an outlet of the casing damage simulation module or the cement column damage simulation module. According to the invention, the field environment of the oil and gas well can be simulated more accurately, and a repair experiment can be carried out on a damaged sleeve or a cement column, so that not only can experimental data support be provided for researchers, but also a more accurate repair scheme can be provided for field operators.

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

The invention provides a desulfonation low-viscosity high-shear strong-inhibition water-based drilling fluid, and belongs to the technical field of oil field chemistry of oil and gas drilling engineering. The de-sulfonation low-viscosity high-shear strong-inhibition water-based drilling fluid is prepared from the following raw materials in parts by mass: 100 parts of water, 0.5 to 1.0 part of a pH regulator, 1 to 3 parts of a lubricant, 0.5 to 0.7 part of a shear strength improving agent, 2 to 4 parts of a filtrate reducer, 2 to 4 parts of an inhibitor, 5 to 15 parts of an auxiliary inhibitor, 1 to 3 parts of a dispersing agent and barite, the barite is not limited in parts, and the barite is added until the required density is reached. The desulfonation low-viscosity high-shear strong-inhibition water-based drilling fluid can effectively inhibit expansion and dispersion of formation water-sensitive minerals in a high-temperature water-sensitive formation environment, maintain the stability of a well wall, guarantee the cleanness of a well hole and improve the drilling efficiency, is environment-friendly and biodegradable, and meets green, safe and efficient drilling requirements.

The invention relates to the technical field of natural gas development, in particular to a deep water gas reservoir dynamic reserve calculation method, which comprises the following steps of: acquiring basic information of a target well; establishing a deep water gas reservoir dynamic reserve calculation equation; correcting a deep water gas reservoir dynamic reserve calculation equation; and solving the corrected deep water gas reservoir dynamic reserve calculation equation. According to the method, the dynamic reserves calculation equation of the deepwater gas reservoir is obtained by establishing the material balance equation of the limited closed water body, and the complex phase state change existing in the development of the deepwater gas reservoir is further considered; the deep water gas reservoir dynamic reserve calculation equation is corrected from the five aspects of condensate water, reverse condensation, water-soluble gas, rock skeleton expansion and formation water invasion, after the corrected deep water gas reservoir dynamic reserve calculation equation is obtained, the corrected deep water gas reservoir dynamic reserve calculation equation is solved, and calculation of the deep water gas reservoir dynamic reserve can be more accurate.

The invention relates to a digital core resistivity numerical simulation and saturation model construction method under deep overpressure and high temperature conditions, and relates to the technical field of oil-gas exploration, and the method comprises the steps: constructing a digital core under the overpressure condition, calculating the clay conductivity and formation water conductivity under the high temperature condition, and obtaining an overpressure and high temperature equivalent digital core model; based on an overpressure and high-temperature equivalent digital core model, through an electrical numerical simulation algorithm, the resistivity and the stratum factor F of water-saturated cores with different porosities phi are calculated, and an F-phi cross plot is constructed; and calculating digital core resistivity and resistivity increase coefficient RI of different water saturation Sw by using a numerical simulation algorithm, and constructing an RI-Sw cross plot. According to the method, a saturation model under the deep actual temperature and pressure conditions can be constructed through equivalence of pressure and temperature by utilizing a digital rock core numerical simulation technology.

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

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

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

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

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

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

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

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

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

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

The invention provides an underground circulating heat removal system and method, and belongs to the crossing field of geothermal development and petroleum engineering. The system comprises a sleeve, a formation water underground circulation assembly and an underground heat exchange device, wherein the formation water underground circulation assembly and the underground heat exchange device are arranged in the sleeve; the underground heat exchange device is connected with the formation water underground circulation assembly; and formation water in the geothermal water reservoir enters the underground heat exchange device along the formation water underground circulating assembly, and the formation water subjected to heat exchange is recharged into the geothermal water reservoir along the formation water underground circulating assembly to form circulating heat removal. By means of the underground formation water circulation assembly, formation water completely circulates underground and does not make contact with the outside, pollution to the formation water in the conveying process is reduced to a certain degree, and blockage of geothermal well rock stratum gaps is avoided as much as possible; according to the method, the same-layer reinjection of the formation water of the single well is realized through sidetrack drilling of the branch well sections, drilling of multiple wells is avoided, and the well drilling cost is saved.

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

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

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