36 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.

This invention belongs to the field of seismic reservoir prediction and intelligent geophysical interpretation technology, specifically involving an intelligent reservoir prediction method for suppressing strong interference anomalies. The method first preprocesses seismic data and uses the generalized S-transform to obtain the time-frequency spectrum of the seismic signal. Then, based on the frequency component variation relationship, fluid flow properties are constructed to enhance reservoir fluid response characteristics and suppress strong response anomaly interference from non-reservoir areas. Furthermore, seismic data and fluid flow properties are jointly input to construct an intelligent reservoir prediction network based on a residual U-Net structure. Multi-scale feature extraction and fusion are achieved through an encoder-decoder structure and skip connections. Finally, the probability prediction result of the reservoir is output. This method can effectively fuse seismic structural information and fluid flow property information, improving the accuracy and stability of reservoir prediction under complex geological conditions, and has good generalization ability and application value.

The application provides a dense reservoir fluid identification method based on physical data double driving, comprising: performing abnormal value correction and fluid category direct marking on conventional logging data to obtain labeled logging data; performing signal self-adaptive time-frequency conversion on the labeled logging data, and calculating porosity, permeability and water saturation to output physical prior feature channels; inputting two-dimensional multi-channel time-frequency spectrum and the physical prior feature channels into a pre-constructed MDSC-TAM neural network model to extract hidden logging signal frequency domain spectrum series structure and global sedimentary rule to obtain a dense reservoir fluid identification result; and performing physical perception constraint and decision output on the fusion feature representation to obtain a fluid type and confidence. The application solves the data scarcity and model black box bottleneck, improves the engineering practicability of the algorithm, and realizes high-precision identification of the dense reservoir fluid and enhanced physical interpretability.

The application discloses a kind of visualization methods for microcosmic action mechanism of steam displacement heavy oil, which comprises: obtaining the porous structure information of rock sample;According to the structure information of rock sample, design pore network structure and make microfluidic chip;Build steam displacement heavy oil visualization implementation system, and adopt steam displacement heavy oil visualization implementation system to collect the phase distribution and temperature distribution of microfluidic chip in displacement process;Boundary extraction is carried out to experimental picture, and the dynamic change process of each phase in displacement process is obtained and the interaction relationship with temperature distribution change is obtained.The application designs pore network chip according to the pore structure information of rock sample, obtains the phase distribution and temperature distribution in displacement process, and is used to study the microcosmic phase distribution characteristics and temperature distribution characteristics of fluid in heavy oil reservoir reservoir, and then the microcosmic mechanism of reservoir fluid movement is explored, so as to provide a practical visualization method for the research of steam drive oil mechanism.

This invention relates to the field of petroleum exploration and development technology, and is a method and system for fluid property identification based on micro-fluorescence thin section technology. The method includes acquiring the micro-fluorescence thin section spectrum of a rock sample; obtaining the true fluorescence area under blue light and the true fluorescence area under ultraviolet light based on the micro-fluorescence thin section spectrum of the rock sample; substituting the true fluorescence area under blue light and the true fluorescence area under ultraviolet light into an extinction index model to obtain an extinction index; and comparing the extinction index with an extinction index evaluation standard to identify fluid properties. This invention establishes an extinction index for identifying reservoir fluid properties. Its extinction index model extracts the pair of sensitive parameters—fluorescence area under blue light and ultraviolet light—by utilizing the spectral variation characteristics between different crude oils and different proportions of water under micro-fluorescence thin section technology. This effectively solves the problem of reservoir fluid property identification, and the method can quantitatively identify reservoir fluid properties.

This application provides a numerical simulation method, apparatus, and storage medium for asphaltene deposition unblocking, belonging to the field of oil and gas field development technology. The method includes: constructing a thermodynamic component model containing asphaltene based on reservoir fluid composition; calculating oil-solid phase equilibrium conditions using equations of state; setting a critical mole fraction for asphaltene precipitation in the oil phase, where precipitation occurs when the actual mole fraction is greater than or equal to the critical value; setting reaction paths for precipitation and unblocking reactions; establishing a porosity-permeability coupled evolution model, where porosity decreases linearly with solid deposition, and permeability decreases power-lawically with decreasing porosity; embedding the above model into a reservoir numerical simulator, and dynamically updating the asphaltene concentration, solid deposition, porosity, and permeability parameters of each grid through time-step numerical solutions.

A device may include a remote pump jack configured to lift reservoir fluids from underground. A device may include an oil tank connected to the remote pump tank, the oil tank being configured to store the reservoir fluids and allow the reservoir fluids to separate into one or more of oil and a headspace vapor. A device may include a pneumatic gas booster connected to the oil tank, wherein the pneumatic gas booster is configured to draw in the headspace vapor during a vapor recovery operation. A device may include the pneumatic gas booster being connected to a liquid nitrogen tank that provides a motive gas to the pneumatic gas booster such that as the pneumatic gas booster draws in the headspace vapor, the motive gas furnishes a stable drive pressure during the vapor recovery operation.

This invention discloses a method for evaluating the influencing factors of proppant breakage rate under reservoir conditions, comprising: S1: using an electric vibrating sieve and a sieve to screen the original proppant sample by particle size, testing the bulk density of the original proppant sample, and dividing the original proppant sample into two parts, I and II, each part being weighed according to a formula; S2: proppant breakage rate test under reservoir closure pressure conditions; S3: proppant breakage rate test under reservoir temperature conditions; S4: proppant breakage rate test under reservoir fluid environment conditions; S5: proppant breakage rate test under reservoir environment conditions; S6: calculating the processed proppant breakage rate according to the formula and analyzing the influence of influencing factors on the proppant breakage rate. The breakage rate testing and analysis method in this invention analyzes the degree of influence of influencing factors on the proppant breakage rate under reservoir conditions, providing experimental guidance for a more in-depth study of the proppant breakage rate mechanism.

The present disclosure relates to the technical field of oil and gas exploration and development, and particularly relates to a reservoir oil and gas detection method, device, equipment, storage medium and computer program. The method comprises: obtaining seismic information and logging information of the reservoir; determining an elastic parameter difference of the reservoir based on the seismic information and the logging information; determining a dispersion attribute parameter of the reservoir based on the seismic information; determining a fluid identification parameter based on the elastic parameter difference and the dispersion attribute parameter; and determining an oil and gas feature of the reservoir based on the fluid identification parameter. The method improves the accuracy of reservoir fluid detection.

The present application relates to the technical field of unconventional reservoir development and drainage, and provides a hydrophilic unconventional oil horizontal well volume fracturing post-soaking time design method, which comprises the following steps: S100, evaluating reservoir wettability and determining that the reservoir is a hydrophilic reservoir; S200, establishing a horizontal well segmented cluster fracturing post-reservoir fluid seepage basic physical model and determining basic conditions of the soaking time design method; S300, determining a soaking time calculation formula based on Darcy's law and seepage velocity; S400, collecting data values of parameters of the soaking time calculation formula; and S500, substituting the data values into the soaking time calculation formula to calculate equivalent reasonable soaking time. The method can achieve the technical effect that unconventional reservoir volume fracturing horizontal wells can be opened and oil can be seen.

The application provides a rock sample water content observation method and device. The rock sample water content observation method comprises the following steps: contacting a rock sample with a water sensitive test paper; collecting an image of a contact area of the rock sample and the water sensitive test paper, and calculating a total area S of the contact area; collecting an image of a color developing area of the water sensitive test paper, and calculating an area S1 of the color developing area; calculating a percentage of the area S1 of the color developing area to the total area S of the contact area, and analyzing water content of the rock sample according to the percentage. Compared with the prior art, the application utilizes sensitivity of the water sensitive test paper and convenience of image collection and processing, establishes a rock sample water content observation method suitable for a field, and has the advantages of simple operation, short observation period and intuitive observation result display, thereby providing a new means and method for reservoir fluid identification and evaluation. The method obtains a relative water content, and can be used for fluid saturation sample screening, comparison and analysis of water content of different rock samples and different layers, and provides a basis for formation fluid property evaluation.

There is provided a system for producing hydrocarbon material from a subterranean formation. The system includes a separator for separating gaseous material from reservoir fluid obtained from the subterranean formation. The system is configured to mitigate interference to the separation.

The application discloses a multi-azimuth multi-frequency reservoir fluid prediction method based on five-dimensional data, and the prediction method comprises the following steps: finding the influence of azimuth anisotropy on reservoir fluid by using the azimuth angle and offset distance information of pre-stack OVT domain five-dimensional data, selecting a dominant azimuth, and establishing a split-azimuth stacking template; on the basis of split-azimuth seismic stacking data, ideal frequency domain data volume is obtained by using a time-frequency analysis method; the frequency sensitive section of the study area is determined by combining the frequency gradient response characteristics of actual well points with different oil contents; the frequency gradient attribute map of the whole study area is calculated, and the reservoir fluid is predicted. The reservoir fluid is effectively identified, and the drilling success rate of lithologic oil and gas reservoirs is improved.

This invention discloses a numerical calculation method for dynamic negative pressure perforation wellbore pressure based on the finite volume method. The method includes designing an explosion-driven mechanical dynamic negative pressure generator; establishing an explosion model of the perforating projectile inside the perforating gun and a model of the negative pressure valve spindle sliding under the explosion pressure of the mechanical dynamic negative pressure generator, simulating and determining the opening time of the dynamic negative pressure generator; establishing transient physical models describing the flow field in the dynamic negative pressure perforation wellbore and the flow field in the perforation string, and performing numerical solutions. Finally, a mechanical dynamic negative pressure perforation experiment is conducted to verify the accuracy of the model. This invention solves the technical problem that existing empirical formulas for calculating dynamic negative pressure perforation wellbore pressure are overly simplified, failing to consider the coupling effect between the gas inside the perforating gun string and the wellbore pressure, the spatial constraint effect of the narrow wellbore, and the reservoir fluid exchange process, resulting in insufficient pressure prediction accuracy and an inability to provide accurate basis for dynamic negative pressure perforation pressure prediction and parameter optimization.

Disclosed herein are systems and methods to obtain representative reservoir fluid samples faster. In embodiments, the methods may include conveying a formation testing tool into a wellbore, pumping reservoir fluid from a downhole formation from the guard probe to at least one flow line at a first flow rate, pumping reservoir fluid from a downhole formation from the clean probe to a second flow line at a second flow rate, wherein a ratio of flow rates between the first flow rate and the second flow rate is held constant until reaching a first pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe, changing the ratio of flow rates between the first and second flow rates, and sampling a reservoir fluid when reaching a second pre-determined value of contamination of drilling fluid filtrate inside the reservoir fluid pumped inside the clean probe.

A method and system for downhole measurements of reservoir temperature and pressure and reservoir fluid compressibility, density, viscosity, and bubble point pressure to obtain an oil formation volume factor (FVF) or a gas to oil ratio (GOR) in real time are disclosed. In embodiments, methods include conveying a downhole formation analysis tool into a wellbore, measuring reservoir fluid compressibility, density, viscosity, and bubble point pressure, and obtaining the oil formation volume factor (FVF) or the gas to oil ratio (GOR) while the fluid sampling tool is still in the wellbore.

The application discloses a kind of based on CT scanning and mercury injection data fusion core geometry model construction method, it is related to oil and gas field development technical field. Including: by three-dimensional CT scanning and image processing algorithm obtains core pore structure data;Through high-pressure mercury injection experiment obtains core pore throat size distribution data;Innovatively, three-dimensional core pore structure data and core pore throat size distribution data are fused, and pore-throat space mapping network is constructed by graph theory, to construct the core geometry model;And combining optimization algorithm dynamically adjusts pore throat size, verifies the core geometry model constructed.This application breaks through the limitation of traditional single experimental method, solves the problem of insufficient precision of core geometry model construction, and provides high-precision input for numerical simulation of fluid migration law in post-polymer flooding reservoir.The error of fluid flow simulation in COMSOL of the core geometry model constructed and experimental measurement result is controlled within ±5%, which is significantly better than traditional method.

This invention relates to the field of oil and gas exploration, specifically to a method, equipment, and medium for identifying the fluid properties of carbonate reservoirs. The method includes establishing a sample well bank of carbonate cavernous reservoirs based on conventional logging and imaging logging data; screening out cavernous oil-gas layers, cavernous oil-water layers, and cavernous water layers, and establishing well logging identification charts for these layers; and identifying the fluid properties of the wells based on the well logging identification charts and conventional logging data from current exploration wells. This invention overcomes the problem that conventional and seismic methods cannot identify the fluid properties of carbonate reservoirs, providing a new method for identifying the fluid properties of carbonate reservoirs.

The present application relates to a method and device for determining the property of carbonate rock diagenetic fluid. The method comprises the following steps: collecting a carbonate rock sample, determining the diagenetic period of the carbonate rock sample; determining the ratio range of the target isotope of the contemporaneous seawater according to the diagenetic period; determining the measured ratio of the target isotope of the carbonate rock sample, and comparing it with the ratio range to determine the diagenetic fluid property of the carbonate rock sample. The method uses existing data accumulation to determine the diagenetic fluid property of the carbonate rock sample in a fast and low-cost manner through the collection of a small amount of carbonate rock sample. The method can be well applied to various types of carbonate rock reservoirs. The property of the carbonate rock reservoir fluid can be accurately identified, thereby helping to find the favorable reservoir development area.

The present application belongs to the technical field of oil and gas reservoir fluid identification, and discloses a gas-water identification method, medium and equipment under complex formation conditions and wellbore structure, which is based on geologic region layering according to salinity and formation temperature, and uses an optimized intelligent algorithm to correct resistivity; for non-severe and severe diameter expansion intervals, neural network method and multiple regression method are used to correct porosity. Combined with neural network, the fast discrimination of fluid properties is realized, a gas-water identification fine chart is established for the stratums after zoning and layering, and a set of comprehensive intelligent fluid identification technology is formed. The present application considers the complex formation conditions of salinity and formation temperature of formation water and the complex wellbore conditions of hole diameter expansion and mud invasion, and creates a set of gas-water identification technology for complex geological factors and wellbore environment, realizes the automatic gas-water identification process and improves the accuracy of the final interpretation conclusion.

The application discloses a kind of based on physical guiding neural operator oil reservoir intelligent dynamic analysis prediction method, belong to oil and gas field development numerical simulation and artificial intelligence field, first based on the data set containing the space-time dynamics of multiphase flow of heterogeneous reservoir model is constructed, and the dimension is reduced by layer slicing method.Processing.Using neural network to extract the space-time evolution characteristics of reservoir fluid, and a double-track multi-head prediction structure is designed, including pressure prediction track and saturation prediction track, wherein the space-time evolution kernel representing non-steady seepage diffusion law is embedded in the pressure prediction track.The design directly uses the physical law as the guiding benchmark for network forward propagation, avoiding the computational disaster caused by solving complex multiphase partial differential equations, and finally optimizing the model by combining multiple constraints such as spatial gradient, boundary and initial conditions.The application realizes the guidance of physical prior to data-driven neural operator, greatly improves the analysis and prediction accuracy, generalization ability and computational efficiency of the model.

This invention provides a reservoir-wellbore coupled numerical simulation method, apparatus, equipment, and medium, belonging to the field of reservoir numerical simulation technology. The method includes: acquiring the current wellbore-reservoir contact surface temperature, reservoir fluid pressure, and mole fraction of each phase; and calling a multiphase, multicomponent flow model for an ultra-deep wellbore and an ultra-deep fault-controlled oil and gas reservoir. First, the relevant data are input into the reservoir model for solution to obtain the parameters corresponding to the next time step. Then, some parameters are input into the wellbore model to obtain the pressure within the wellbore. If the pressure difference between the reservoir fluid pressure and the pressure within the wellbore is less than a preset threshold, the pressure within the wellbore at the next time step is output. This invention significantly improves the prediction accuracy of pressure within the wellbore by coupling the wellbore and reservoir models, enabling optimization of reservoir production plans and effective guidance for reservoir management, thereby improving recovery rate and economic benefits.

This invention belongs to the field of oil and gas development, specifically relating to a method for characterizing reservoir water cut distribution. The method includes: establishing oil-water phase permeability curves based on experiments measuring the relative permeability of two-phase fluids in rocks; combining this with reservoir water saturation data to obtain oil phase relative permeability field data and water phase relative permeability field data; establishing fitting relationships between crude oil viscosity and reservoir pressure, and between crude oil volume coefficient and reservoir pressure, based on reservoir fluid property analysis experiments; combining this with reservoir pressure data to obtain oil phase viscosity field data and oil phase volume coefficient field data; establishing a water cut calculation formula; and establishing a reservoir numerical model based on the calculation formula to generate a water cut distribution map. The water cut distribution map generated using this method can characterize the water cut distribution at different stages of reservoir development, providing a more refined representation of reservoir water cut distribution and potential, and offering a more scientific basis for evaluating water drive development effectiveness and formulating reservoir adjustment plans.

The application provides a method for resistivity correction of clastic rock reservoirs, and belongs to the technical field of oil and gas resource reservoir exploration; the method comprises the following steps: S1, standardizing the logging curve of the existing well of the reservoir to be analyzed to obtain a standardized logging curve; S2, based on the standardized logging curve and core data obtained in step S1, a multi-mineral model is used to solve the lithology profile of the reservoir to be analyzed, and the gravel content and the lime content of the reservoir to be analyzed are determined; S3, according to the gravel content and the lime content determined in step S2 and the resistivity to be corrected, the corrected resistivity is obtained according to a resistivity correction formula, and a correction chart is established. Compared with the prior art, the application realizes the resistivity correction of the clastic rock reservoirs containing gravel and lime, and improves the accuracy of the fluid logging interpretation of the complex clastic rock reservoirs.

The embodiment of the application discloses a buried hill reservoir fluid property identification method and device, the method comprises the following steps: obtaining detection results corresponding to a plurality of detectors on a logging instrument; the plurality of detectors comprise a near detector, a far detector and a long detector, and the detection results comprise a total gamma count curve, non-elastic gamma energy spectrum data and / or capture energy spectrum data; determining an index data body according to the detection results corresponding to two detectors in the plurality of detectors; determining a curve envelope feature of a target reservoir section according to the total gamma count curve corresponding to the near detector and the long detector after non-reservoir section calibration processing; and identifying the fluid property of the target reservoir section according to the local index data corresponding to the target reservoir section in the index data body and the curve envelope feature of the target reservoir section. The embodiment of the application realizes the buried hill reservoir fluid property identification based on multi-parameter coupling analysis, and can ensure the pertinence and accuracy of the fluid property identification.

The invention discloses a method and system for simulating plunger gas lift, and the method comprises the steps: obtaining the correlation among the mass of a gas column above a plunger, the height of the plunger and the blowout flow of surface gas according to the expansion characteristics of the gas column above the plunger before the plunger ascends to a liquid slug at the top of the plunger and reaches the ground; the method comprises the following steps of: collecting reservoir fluid, determining the flowing characteristic of the reservoir fluid into an annular space based on the flowing characteristic of the reservoir fluid into an oil pipe and a casing pipe, and then constructing the correlation between the mass of the produced hydrops and the ascending speed of the plunger before the plunger continuously ascends to reach the ground; according to the expansion characteristics of the gas column at the bottom of the plunger, the correlation between the mass of the gas column at the bottom of the plunger and the blowout flow of the surface gas when the plunger stays on the ground is obtained; after the plunger descends to the liquid slug entering the bottom of the plunger, the descending speed of the plunger and the new liquid slug at the top and the new liquid slug at the bottom are respectively related. According to the invention, plunger gas lift full-period dynamic simulation is realized, and the method has good applicability and reliability.

The application discloses a kind of oil and gas reservoir fluid-solid coupling seepage simulation methods based on fluid mechanics, grid division is carried out to geological model, and the gas-water two-phase seepage model of fluid in grid is established, the gas-water two-phase seepage discrete model between adjacent grids is obtained by time-space discretization to gas-water two-phase seepage model;Sparse matrix is established based on grid, and the compression is carried out to sparse matrix;Fluid pressure field is solved to the gas-water two-phase seepage discrete model based on multigrid algorithm;In the solving process, based on gas-water two-phase fluid mass conservation model, the saturation of each phase fluid in each grid in geological model, gas high-pressure physical parameter is updated.Until the termination condition of solution result is reached;The application can more efficiently and accurately simulate carbonate rock triple medium gas-water two-phase fluid-solid coupling seepage.

A method and a system for determining hydrocarbon reservoir production with a coiled tubing having a miniature multi-phase flowmeter. Deploying the miniature multi-phase flowmeter in the wellbore by the coiled tubing orients the miniature multi-phase flowmeter in a wellbore extending to a hydrocarbon reservoir containing a multi-phase reservoir fluid. The miniature multi-phase flowmeter has a venturi oriented in along a longitudinal axis of the coiled tubing and multiple sensors. The multi-phase reservoir fluid is conducted from the wellbore through the coiled tubing to the miniature multi-phase flowmeter. The venturi and sensors sense conditions including a pressure, a differential pressure, a temperature, a bulk fluid flow rate, an electrical capacitance, and an electrical conductance of the multi-phase reservoir fluid. Based on the conditions of the multi-phase reservoir fluid, a production condition of the hydrocarbon reservoir is determined.