330 results about "Reservoir fluid" patented technology

The invention relates to an array electric imaging logging based reservoir oil-water identification method and system. Aiming at the resistivity distribution characteristics of mud-invaded formations, a 'five-parameter formation model' is established, which is adapted to the requirement for simulating the resistivity distribution characteristics of different mud types and different invaded formations, and is pioneering in the aspects of forward-inversion models and processing methods of array electric imaging logging; and based on a 'five-parameter inversion' method for array electric imaging logging, an operation of carrying out resistivity distribution profile reconstruction on mud-invaded formations is performed, which reflects the actual differences between different resistivity distribution characteristics or change rules of mud-invaded oil formations or water formations. The method has stronger practicability, and is pioneering in the actual application aspects of qualitative identification and quantitative calculation on reservoir fluid properties.

The invention discloses an oil reservoir dynamic monitoring method and device. The method comprises the steps that sound wave data and temperature data collected by distributed optical fiber sensors in real time are obtained; the distributed optical fiber sensors are deployed in a plurality of injection and production wells according to a preset deployment rule; the sound wave data and the temperature data are input into an oil reservoir dynamic monitoring model, an oil reservoir fluid three-dimensional dynamic graph is output, and the oil reservoir fluid three-dimensional dynamic graph displays oil reservoir fluid state data; the reservoir dynamic monitoring model is obtained by training a Transform model by using historical sound wave data, temperature data and reservoir multi-source information in advance; in the training process, time and space grid alignment processing is carried out on historical sound wave data, temperature data and oil reservoir multi-source information, time-space sequence features are obtained, and the model identifies oil reservoir fluid state data in the time-space sequence features based on self-attention and multi-attention mechanisms. The accuracy and reliability of oil reservoir monitoring and analysis can be improved.

The invention relates to a lacustrine facies shale conductive model considering organic matter influence and a saturability evaluation method, and belongs to the technical field of unconventional oil and gas reservoir oiliness evaluation, and the method comprises the following steps: 1) representing fluid information in a shale sample based on a pressure-maintaining closed sample and a two-dimensional nuclear magnetic resonance technology; 2) according to the organic carbon content and the clay content of the shale, dividing the lithology type of the lacustrine facies shale, and analyzing the relation between different lithology resistivity values and the porosity of free water and bound water; 3) selecting a siltstone interlayer sample, and inversely calculating a cementation index and a saturation index of the inorganic pore conductive network; 4) establishing a lacustrine facies shale parallel conductive model, and calibrating rock-electricity parameters according to lithology; 5, a lithology discrimination chart, a TOC prediction model, a bound water content prediction model and an effective porosity calculation model are established, and the oil saturation is explained according to different lithologies in combination with the lacustrine facies shale parallel conduction model.According to the method, accurate shale reservoir fluid information is provided, and a brand new thought is provided for rock electrical parameter calibration.

The invention discloses a CO2 storage multi-field coupling safety evaluation method considering fracture evolution, and relates to the technical field of complex oil and gas reservoir development, and the CO2 storage multi-field coupling safety evaluation method comprises the following steps: s1, constructing and solving a multi-field coupling model; s2, virtual crack grid construction and expansion: according to the updated model stress field parameters, judging whether cracks are generated or not, and if so, constructing and expanding a corresponding virtual crack grid; s3, evaluating the integrity of the cover layer: after each time step is finished, evaluating the integrity of the cover layer; and continuing numerical simulation of the next time step until the simulation is finished. According to the method, comprehensive coupling of multiple physical fields such as crack generation and expansion, CO2 seepage, heat transfer between the injected CO2 fluid and the reservoir and between the injected CO2 fluid and the reservoir fluid, geological stress redistribution and the like in the CO2 storage process is fully considered, so that the spatial and temporal change of each physical field in the reservoir in the CO2 injection process can be truly represented, the simulation precision is greatly improved, and the simulation efficiency is improved. And the uncertainty caused by fixed parameters or simplified processing is effectively reduced.

The invention discloses a reservoir fluid identification method, device and equipment and a medium, and relates to the technical field of oil and gas field exploration. The invention provides a multi-level nested reservoir fluid identification method based on geological mode constraint for double-medium tight sandstone. For different reservoir types, a preset algorithm is utilized to fuse the comprehensive logging parameters and the proposed fluid sensitive factors suitable for the double-medium tight sandstone, and fluid discrimination parameters suitable for different reservoir types are constructed. On the basis, reservoir types are divided by comprehensively considering the coupling action result of the matrix and the tectonic fracture, the difference of fluid characteristics of different reservoir types is determined, and based on the classification constraint of a geological mode, the different reservoir types are divided, and the fluid type of the tight sandstone reservoir is identified by using an integrated identification model. Logging curve data for fluid identification are easy to obtain, the fluid identification precision is high, the identification efficiency is high, and the method can be widely applied to reservoir fluid identification of double-medium tight sandstone.

The invention provides a tight oil reservoir fluid occurrence type identification method and system based on nuclear magnetic resonance, and belongs to the technical field of petroleum geology exploration and development. The method comprises the following steps: on the basis of comparison between a nuclear magnetic resonance T2 relaxation time cumulative distribution curve of a tight oil reservoir sample and a high-pressure mercury injection pore throat diameter cumulative distribution curve, dividing pore throat types, and converting T2 relaxation time into pore throat diameters; judging occurrence fluids in different types of pore throats through a nuclear magnetic resonance spectrum to obtain fluid occurrence types corresponding to different signal domain ranges, and calculating the relative fluid content of each fluid occurrence type; and based on the signal domain range of each fluid occurrence type of the plurality of samples, establishing a nuclear magnetic resonance fluid occurrence type identification chart, and defining an identification standard of each fluid occurrence type. According to the method, the pore size distribution of the T2 relaxation time is combined with the nuclear magnetic resonance spectrum, the pore size range corresponding to the fluid occurrence type is determined, and the relative content of the fluid is calculated through the signal intensity of each signal domain, so that the accuracy is higher.

The invention belongs to the technical field of shale oil exploration and development, and particularly relates to a two-dimensional nuclear magnetic resonance logging fluid saturation calculation method and system. The calculation method comprises the following steps: acquiring attribute data of a reservoir; determining lithology sensitive parameters and shale indexes of the reservoir according to the attribute data; determining a reservoir type according to the attribute data, the lithology sensitive parameters and the shale index; determining a fluid identification model of the reservoir according to the reservoir type and the nuclear magnetic resonance response characteristics; and calculating the fluid saturation of the reservoir by using the fluid identification model. When reservoir fluid identification and fluid saturation quantitative calculation are carried out, multiple reference indexes are referred to at the same time, then the reservoir fluid saturation of the reservoir can be accurately calculated, and the identification accuracy is high.

The invention provides an igneous rock fluid identification method based on a CXDF algorithm, and the method specifically comprises the following modules: S1, data preprocessing: obtaining core and logging data of a research area, and sorting the data into a table file in an xlsx format; performing logarithm processing on the specified logging data; performing normalization processing on the logging data; 78% of the preprocessed data is a training data set, and 22% of the preprocessed data is a verification data set; dividing a training data set label into two parts, namely multi-hydrocarbon and low-hydrocarbon; s2, model establishment: constructing a fluid identification model based on a CXDF algorithm and other artificial intelligence algorithms; constructing a simulation well based on the verification data set; identifying the simulated well according to the fluid identification model; s3, model optimization: performing model evaluation and model comparison based on a table, a radar map and a histogram; and determining an optimal fluid identification model. According to the method, rebalance processing is carried out on the data set based on an adaptive multi-target group cross optimization algorithm, and recognition of the complex lithologic igneous rock reservoir fluid is realized in combination with an integrated learning model.

The invention discloses a reservoir fluid identification method, system and device and a readable storage medium. The method comprises the following steps: acquiring seismic data, logging data and electromagnetic data; respectively calculating seismic apparent resistivity data, logging apparent resistivity data and electromagnetic apparent resistivity data according to the seismic data, the logging data and the electromagnetic data; performing normalization processing on the seismic apparent resistivity data, the logging apparent resistivity data and the electromagnetic apparent resistivity data to obtain seismic conversion data, logging conversion data and electromagnetic conversion data of a depth domain; reconstructing the seismic conversion data, the logging conversion data and the electromagnetic conversion data by using wavelet transform to obtain diploid resistivity data; and reservoir fluid identification is carried out based on the diploid resistivity data. According to the reservoir fluid identification method, system and device and the readable storage medium provided by the embodiment of the invention, the accuracy of reservoir fluid identification can be improved.

The invention relates to the technical field of oil and gas geophysical exploration, and particularly discloses a tight sandstone gas reservoir fluid mobility gradient attribute prediction method and system.The method comprises the steps that a reflection coefficient expression containing a fluid mobility item is constructed, and a formula for calculating fluid mobility through frequency dispersion attributes is deduced; constructing a fluid mobility gradient attribute related to the frequency and the incident angle of the seismic wave; the method comprises the following steps: establishing a double-pore rock physical model, generating a synthetic seismic record, applying frequency variation AVO inversion to the synthetic seismic record, and extracting a bulk modulus dispersion attribute and a shear modulus dispersion attribute; and calculating the fluid fluidity changing along with the frequency and the incident angle, and calculating the gradient attribute of the fluid fluidity based on a gradient attribute calculation formula and the fluid fluidity. According to the method, seismic wave frequency dispersion and attenuation response caused by permeability and gas saturation are fully utilized, the seismic gradient attribute of the fluid fluidity and the calculation method are constructed, and high-precision prediction of the fluid fluidity by applying seismic signal elasticity and frequency dispersion rock physical information is realized.

The invention relates to the technical field of oil and gas geophysical exploration, in particular to a high-resolution seismic inversion recognition method for a thin and small reservoir of an oil reservoir. The method comprises the following steps: performing digital core model construction on a thin and small reservoir core sample to obtain a three-dimensional digital core model; carrying out multi-mineral component quantitative analysis on the thin and small reservoir core sample to obtain mineral components and distribution data; performing fracture geometric analysis on the three-dimensional digital core model to obtain fracture geometric analysis data; constructing a microscopic rock physical model according to the fracture geometric analysis data and the mineral composition and distribution data, and calculating physical model parameters to obtain microscopic rock physical parameters; and calculating matrix pore elastic parameters according to the microscopic rock physical parameters to obtain pore-containing dry rock elastic parameters. According to the method, the problems that a traditional method is low in resolution and influences of reservoir fluid and fractures are ignored are effectively solved, and high-precision recognition and fine description of the thin and small reservoir are achieved.

The invention discloses a reservoir fluid property identification method, system and device and a storage medium. The method comprises the steps that inversion apparent resistivity data and logging data of a research area are acquired; performing first-order derivation on the inversion apparent resistivity data to obtain first-order derivation data; based on logging data, corresponding weight coefficients are distributed to the average thin layer thicknesses of different reservoirs, and the resistivity corresponding relation between the apparent resistivity and the logging resistivity is established; determining logging resistivity value difference standard data among different reservoir fluids in the research area according to the logging data; apparent resistivity value difference standard data are determined according to the resistivity corresponding relation and the logging resistivity value difference standard data; and determining fluid boundaries of different reservoirs according to the apparent resistivity value difference standard data and the sawtooth points of the first-order derivation data. According to the reservoir fluid property identification method, system and device and the storage medium provided by the embodiment of the invention, the accuracy of reservoir fluid property identification can be improved.

A method of mapping reservoir fluid in a mature field includes identifying a region of interest within a hydrocarbon field, drilling a plurality of production wells through the region of interest, and collecting mud gas data as each production well is drilled. This mud gas data is used to generate a reservoir fluid property log, such as gas-oil ratio log, along a length of each of the production wells, which is in turn used to generate a refined model based on the 4D seismic data. The refined model permits better reservoir fluid mapping and has an improved vertical resolution at the region of interest than the first model of the field.

The invention relates to the oil and gas production industry and is intended for studying the physical properties of reservoir fluids using PVT analysis. Proposed is a device for carrying out thermodynamic studies which comprises: a cell body (26), a piston (20), sealing elements (2, 6, 23), a mixing device, a pressure sensor (7), a temperature sensor, an inlet valve (9), an outlet valve (10), a measuring device, a mechanical actuator of the piston, an electric heater (11), a cooling device (12), a system for tilting the cell body, and a control unit. The cell body comprises a mount consisting of a mount body (1) and a viewing window (3) with a sapphire pane. The result is an increase in the reliability, quality and accuracy of measurements of a sample.

The invention relates to the technical field of oil and gas field development, in particular to an ultra-deep gas well production string multi-mode leakage simulation experiment device and method. According to the technical scheme, the outer side of a shaft temperature and pressure coupling simulation system is connected with a reservoir gas supply simulation system, the middle of the shaft temperature and pressure coupling simulation system is provided with a multi-mode leakage simulation assembly, the lower end of a production oil pipe is connected with a reservoir-shaft coupling connector, and the upper portion of one side of a layered sand filling seepage tank of the reservoir gas supply simulation system is connected with a confining pressure loading unit through a pipeline; the lower portion of the layered sand filling seepage tank is connected with a reservoir fluid supply unit, and the outlet end of the layered sand filling seepage tank is connected with a reservoir-shaft coupling connector through a pipeline. The experimental device has the beneficial effects that the experimental device for coupling the reservoir and the shaft is constructed, and the multi-mode leakage simulation assembly is adopted to realize body perforation leakage simulation and screw thread sealing failure simulation, so that the simulation of the ultra-deep gas well under complex working conditions is realized, and a scientific basis and a technical support are provided for leakage prevention and control of a production string of the ultra-deep gas well.

The invention discloses a reservoir fluid identification method and device based on nuclear magnetic resonance T2 spectrum cutoff value backward movement, and relates to the technical field of petroleum logging, and the method comprises the steps: determining T2 spectrum characteristics of a movable fluid according to the obtained production data of a target oil field work area and nuclear magnetic resonance logging data, determining a corresponding T2cutoff critical value based on the peak value of the movable fluid in the T2 spectrum characteristic; determining the target value of the movable fluid based on the maximum T2 value of the spectrum peak in the T2 spectrum characteristic and the T2cutoff critical value; wherein the target value is used for representing the oiliness of the reservoir; analyzing the target values of the movable fluids to obtain a limit value of the target values among the movable fluids; and identifying a target value of the to-be-identified reservoir fluid based on the limit value, and determining the reservoir fluid property of the to-be-identified reservoir fluid according to an obtained identification result. Therefore, the fluid property in the reservoir can be judged according to the nuclear magnetic resonance T2 spectrum.

The invention discloses a displacement potential energy gradient oriented injection-production reconstruction optimization method between fracturing segments, and relates to the technical field of oil and gas field development. The method comprises the following steps: firstly, establishing an oil reservoir three-dimensional numerical model according to oil reservoir interpretation data, simulating in an oil reservoir numerical simulator by using the oil reservoir three-dimensional numerical model to obtain a global pressure field and a fluid flow velocity change condition in the oil reservoir, constructing a fluid potential field model, and determining potential energy gradients among injection-production units; constructing an objective function and setting constraint conditions by taking the most balanced potential energy gradient distribution among all injection and production units in the fluid potential field model as an optimization objective, solving the objective function based on a particle swarm algorithm, and optimizing the horizontal well multi-stage fracturing inter-section injection and production scheme to obtain the optimal horizontal well multi-stage fracturing inter-section injection and production scheme. The control device is used for controlling the injection-production process device between the multistage seam sections of the horizontal well, quantitative characterization and active control of an oil reservoir fluid potential field are achieved, and a basis is provided for improving the injected fluid sweep volume and the crude oil recovery rate of an oil reservoir.

A system and method for digitally managing a CO2 injection and mineralization process within a subterranean geologic reservoir and a subterranean igneous rock formation. The system includes a processor with circuitry with program instructions configured to measure parameters of an injection fluid and a reservoir fluid, calculate injection data including the amount of CO2, a tracer, and supplementary substances effective to maintain a predetermined CO2 to tracer mass ratio in the injection fluid or the reservoir fluid, and inject the injection fluid into the subterranean geologic reservoir and / or the subterranean igneous rock formation to manage the CO2 injection and mineralization process, a measuring device connected to the processor, an injection device connected to the processor.

The invention provides an intelligent oil reservoir simulation and safety prediction system. The system comprises a parameter setting module, a numerical simulation software generation module, an oil reservoir simulation and safety prediction module, an information interaction module, an application management module and a program modularization module, the parameter setting module is used for acquiring numerical simulation parameters set by a user from a user side and importing the numerical simulation parameters into the numerical simulation software generation module; configuring numerical simulation parameters in a human-computer interface in the parameter setting module, wherein the numerical simulation parameters comprise well, reservoir, fluid and well network parameters; the well network parameters comprise a well network type, a well group size, a well name and a well number, grid mapping of a well, a position of the well, a control radius of the well, a grid influence range of the well and yield data of the well; and the numerical simulation software generation module combines the obtained numerical simulation parameters with a preset parameterized model and an intelligent optimization algorithm through a neural network model after receiving the numerical simulation parameters.

The invention discloses a method and device for determining the position of a reservoir fluid channeling channel and a storage medium, and belongs to the technical field of oil and gas exploitation and carbon sequestration. The method comprises the steps that in the process of injecting preset gas into a target reservoir, it is determined that a channeling channel exists in the target reservoir; performing grid division on the region where the target reservoir is located to obtain a plurality of reservoir grid regions; acquiring a first reservoir gas flow rate and a first reservoir pressure value corresponding to the current time step of each reservoir grid region, and a second reservoir gas flow rate and a second reservoir pressure value corresponding to the previous time step of each reservoir grid region; and according to the first reservoir gas flow rate, the first reservoir pressure value, the second reservoir gas flow rate and the second reservoir pressure value, determining a target reservoir grid region covered by the channeling channel in the plurality of reservoir grid regions so as to obtain the position of the channeling channel in the target reservoir, according to the invention, the position of the channeling channel in the target reservoir can be accurately determined.

The invention discloses a high-pressure CO2 oil displacement micro-fluidic chip device which comprises an upper polar plate, a middle partition plate, a lower polar plate, a speed measurement module, a porous medium radial flow module and a liquid outlet module, the speed measurement module is arranged on the upper surface of the middle partition plate; the porous medium radial flow module and the liquid outlet module are arranged on the upper surface of the lower polar plate; the upper polar plate, the middle partition plate and the lower polar plate are sequentially stacked from top to bottom; the speed measurement module is connected with the porous medium radial flow module; and the porous medium radial flow module is connected with the liquid outlet module. According to the device disclosed by the invention, a pore throat structure in rock is simulated by constructing a micron-sized or even smaller complex flow channel, and the CO2 flooding crude oil flow characteristic and the CO2 distribution rule are simulated; a transparent visualization device structure is designed, and visualization of the action mechanism of the CO2 oil displacement system and the reservoir fluid distribution characteristics is guaranteed.

The invention discloses a reservoir fluid identification method and system based on nuclear magnetic T2 spectrum morphological parameters, and the method comprises the following steps: calculating nuclear magnetic T2 spectrum morphological parameters based on nuclear magnetic logging data; constructing sample data according to the interpretation conclusion of the reservoir position and the T2 spectrum morphological parameters; training a pre-established fluid identification model by using the sample data; and inputting the target nuclear magnetic logging data into the trained fluid identification model to obtain a reservoir fluid identification result. And the fluid identification model is a Transform model. According to the method, an intelligent learning algorithm is adopted, rapid and effective reservoir fluid identification is realized based on nuclear magnetic T2 spectrum morphological parameters, the influence of human experience factors is reduced, and the fluid identification model can learn the form of the nuclear magnetic T2 spectrum corresponding to each explanation conclusion according to the label value; therefore, the reservoir fluid property can be quickly and effectively determined according to the morphological parameters of the new well T2 spectrum.

The present disclosure relates to techniques for prediction of reservoir fluid properties of a hydrocarbon reservoir fluid, such as the density, the saturation pressure, the formation volume factor and the gas-oil ratio of the reservoir fluid. To predict the reservoir fluid properties, a model is generated by selecting a subset of available reservoir samples based on a degree of biodegradation of the samples, generating an input data set comprising input data and target data, the input data comprising measured or predicted mud-gas data; and generating a model using the input data. The application of this technique allows a continuous log of the selected property to be generated using mud-gas data collected during the well drilling process.

The invention provides an oil and gas reservoir fluid high-pressure physical property testing device and method, and belongs to the field of oil and gas field development, the device is composed of a constant temperature box, a PVT kettle body, a screw pump, a piston, a camera, a light source module and a stirrer, the PVT kettle body is placed in the constant temperature box, the PVT kettle body is made of a transparent material, a cylindrical inner cavity is formed in the PVT kettle body, and the screw pump is arranged in the inner cavity; a first guide hole and a second guide hole are respectively formed in the upper part and the lower part of the inner cavity to form a channel for fluid to enter and exit from the PVT kettle body, the piston is arranged in the inner cavity, the screw pump is connected with the piston, the stirrer is arranged in the inner cavity, the camera is arranged outside the constant-temperature box, and the light source module is arranged inside the constant-temperature box. The method is implemented through the testing device and comprises a high-pressure fluid sample transfer test and a single degassing test. According to the device and the method provided by the invention, the high-pressure physical property parameters of the fluid can be accurately measured by a small amount of samples, and key technical indexes are provided for oil-gas field development.

The invention provides a method for determining the pore diameter lower limit and the effective pore volume ratio of movable fluid. The method comprises the steps that the temperature of each sample under the stratum in-situ condition is calculated according to the ground temperature gradient and the burial depth; correcting the surface tension coefficient of the water by using the calculated temperature; determining an average contact angle of water and shale; calculating capillary force, enabling the capillary force to be equal to reservoir fluid pressure, and calculating the lower limit of the aperture of the movable water; carrying out carbon dioxide adsorption, liquid nitrogen adsorption and mercury injection experiments on the sample to obtain connectivity pore volume-pore size distribution, and calculating effective pore volume in combination with a movable water pore size lower limit; carrying out a low-field nuclear magnetic resonance experiment, calculating the total pore volume of macropores, obtaining the total pore volume of small pores in combination with a carbon dioxide experiment, and finally calculating the total pore volume; and calculating the pore volume ratio of the effective pores by using the pore volume of the effective pores and the total pore volume. According to the method, the evaluation precision of the lower limit of the pore diameter of the shale reservoir movable fluid and the pore volume ratio of the effective pores is effectively improved, and the test cost is reduced.

The invention relates to the technical field of physical logging, and provides a complex pore structure reservoir fluid identification method based on a dynamic resistivity lower limit, which comprises the following steps: obtaining experimental data of each core sample: irreducible water saturation and values of rock electrical parameters m and n; respectively establishing models of irreducible water saturation, m and n changing along with the pore structure; the formation water resistivity at the formation temperature T is calculated according to the formation water mineralization degree, and then the water saturation and the resistivity lower limit value dynamically changing along with the pore structure are obtained according to the formation water resistivity; obtaining a multi-dimensional fluid identification chart of the irreducible water saturation, the water saturation and the resistivity lower limit value dynamically changing along with the pore structure; the actual porosity, the actual permeability and the actual resistivity of the stratum are measured, measured data are projected to the multi-dimensional fluid identification chart, and the actual irreducible water saturation and the actual water saturation are obtained. The method solves the problems that the fluid property of the reservoir with the complex pore structure is difficult to quickly identify and the accuracy is low.

The invention provides a method for identifying the water content of a reservoir based on light hydrocarbon logging. The method comprises the following steps: acquiring light hydrocarbon logging data of an oil and gas reservoir to be evaluated; selecting total hydrocarbon abundance, benzene and toluene / benzene in the light hydrocarbon logging data as light hydrocarbon parameters; establishing a two-dimensional atlas through the intersection of benzene and toluene / benzene in the light hydrocarbon parameters, establishing a three-dimensional atlas through the total hydrocarbon abundance and the change of benzene and toluene / benzene, dividing the boundaries of an oil layer, an oil-water layer and an oil-containing water layer, and quantitatively explaining and evaluating the fluid properties of the reservoir. According to the method, the light hydrocarbon logging technology is utilized, two-dimensional and three-dimensional interpretation maps are formed through intersection by selecting light hydrocarbon parameters such as total hydrocarbon abundance, benzene and methylbenzene, the interface and the water content of the reservoir fluid are quantitatively recognized, the coincidence rate of actual interpretation and evaluation of the reservoir fluid is increased, the exploration and development cost of an oil field is effectively reduced, and the purpose of improving the oil testing effect is achieved; the method is easy to operate, high in identification and evaluation accuracy, high in universality and wide in application range.

A system for generating electrical power may include a flowline having an inlet that receives reservoir fluid at a first pressure, an outlet that outputs the reservoir fluid at a second pressure, a first flow path between the inlet and the outlet, and a second flow path between the inlet and the outlet, in parallel with the first flow path. The difference between the first pressure and the second pressure may include a pressure differential, and the system may include a valve that adjusts the pressure differential. Additionally, the system may include a turbine disposed along the second flow path that generates mechanical energy from a flow of the reservoir fluid induced by the pressure differential, and the mechanical energy may be converted to electrical energy.

A reservoir fluid can be produced from a subterranean formation. The reservoir fluid can include water and hydrocarbons such as oil. It is oftentimes desirable to limit the amount of water that is produced, so a higher ratio of hydrocarbons can be produced. Portions of the subterranean formation can have an initial permeability to water. A relative permeability modifier (RPM) package including a surfactant and a polymer can be used in these portions to restrict or prevent water from being produced. The relative permeability modifier package can increase the hydrophobicity of the portion that allows the hydrocarbons to flow through while substantially limiting the amount of water. The relative permeability modifier can coat the surfaces of substances in the formation whereby the permeability to an aqueous fluid is reduced from the initial permeability. The formation can be a high-temperature formation of 230° F. (110.0° C.) or greater.

A method for acquiring the storage potential of a saline aquifer. The method comprises: acquiring the area of a research zone, the density of carbon dioxide under a stratum pressure, the thickness of an oil reservoir, the porosity of the oil reservoir, the irreducible water saturation of the oil reservoir, a reservoir fluid volume coefficient, a carbon dioxide storage efficiency factor, and stratum data; on the basis of the stratum data, determining estimated storage areas; on the basis of the area of the research zone and the estimated storage areas, determining a target storage area; and on the basis of said values, calculating a storage potential value of a saline aquifer in a target region. Further disclosed are an apparatus (400) for acquiring the storage potential of a saline aquifer, and an electronic device (500), a storage medium, a computer program product and a computer program.