Phase state detection method and system for oil and gas reservoir fluid

Abstract

The invention relates to the technical field of fluid detection, in particular to a phase state detection method and system for oil and gas reservoir fluid, and the method comprises the following steps: extracting pressure, temperature and volume parameters based on the multi-point temperature and pressure sampling data of the oil and gas reservoir fluid, calling a gas-liquid ratio sensor to record the gas-liquid ratio change, and matching the pressure and volume data point by point, and calculating a gas-liquid ratio change trend through a time sequence, and generating a gas-liquid ratio dynamic data set. According to the invention, various data are extracted through temperature and pressure sampling, the gas-liquid ratio is recorded in combination with the gas-liquid ratio sensor, the multi-dimensional monitoring capability of the fluid state is improved, the analysis depth of the gas-liquid ratio change rule is enhanced by comparing the gas-liquid ratio change rate with the pressure and volume parameters, and the gas-liquid ratio change rule is analyzed in combination with the pressure gradient and volume characteristics. The method optimizes the recognition of the boundary of a multiphase region in a complex environment, depicts the states of gas-liquid two-phase and multiphase regions through the correlation analysis of pressure gradient and gas-liquid ratio data, and provides comprehensive support for the dynamic monitoring and phase state distribution analysis of oil and gas reservoir fluid.

Description

Technical Field

[0001] The present invention relates to the technical field of fluid detection, and in particular to a phase state detection method and system for oil and gas reservoir fluid. Background Art

[0002] The field of fluid detection technology includes the detection and analysis of the physical properties and chemical composition of various fluids. The core content of this technical field includes the determination of fluid pressure, temperature, density, viscosity, component ratio and other parameters through instruments and detection methods to accurately obtain the basic properties and state information of the fluid. Fluid detection technology is widely used in industrial production, oil and gas extraction, chemical processes and other scenarios, focusing on specific links such as collecting fluid samples, testing fluid status and analyzing fluid composition. It usually completes comprehensive detection and evaluation of fluids through instrument analysis, sample processing, physical property testing and other means.

[0003] Among them, the phase state detection method of oil and gas reservoir fluid refers to the technical means of performing phase state analysis on oil and gas reservoir fluid samples. The subject of this patent is aimed at multiphase fluids in oil and gas reservoirs, and its specific phase state characteristics are determined by measuring fluid pressure, temperature and component ratio. Specifically, after collecting samples using oil and gas sample collection equipment, the pressure and temperature are adjusted through experimental equipment and measurement methods to construct different phase state environments, and the components in the oil and gas mixture are separated and quantitatively analyzed to determine its phase distribution characteristics under specific conditions.

[0004] The existing technology mainly constructs the phase environment through single-point sampling and single pressure and temperature adjustment, which is difficult to cope with the multi-point and multi-dimensional dynamic characteristics in complex oil and gas reservoirs, resulting in an incomplete description of the overall state of the fluid; in the study of gas-liquid ratio changes, it usually only relies on static parameter measurement, ignoring the dynamic change characteristics of the gas-liquid ratio in the pressure and volume conditions, and it is difficult to reflect the real distribution characteristics of the fluid in a complex environment; for the identification of gas-liquid two-phase transition points and phase separation points, the existing technology mostly relies on experimental analysis under fixed conditions, lacks analysis of distribution areas under multi-dimensional gradient conditions, and cannot achieve accurate positioning of the boundaries of multi-phase regions; in the analysis of multi-phase regions, the existing technology relies on separation experiments and component analysis for single-point determination, lacks the induction of dynamic synergistic characteristics under multi-point conditions, and is difficult to effectively reveal the overall distribution law of multi-phase states. These deficiencies make it difficult for the existing technology to provide comprehensive fluid state detection and phase distribution characteristics analysis in complex oil and gas reservoir environments, limiting its actual application effect. Summary of the invention

[0005] The purpose of the present invention is to solve the shortcomings in the prior art and to propose a phase state detection method and system for oil and gas reservoir fluid.

[0006] In order to achieve the above object, the present invention adopts the following technical scheme: a phase state detection method of oil and gas reservoir fluid, comprising the following steps: S1: Based on the multi-point temperature and pressure sampling data of oil and gas reservoir fluids, extract the pressure, temperature and volume parameters, call the gas-liquid ratio sensor to record the change of gas-liquid ratio, match the pressure and volume data point by point, calculate the change trend of gas-liquid ratio through time series, and generate a dynamic data set of gas-liquid ratio; S2: Based on the gas-liquid ratio dynamic data set, the gas-liquid ratio change rate is compared with the pressure and volume parameters item by item, the pressure and volume differences are calculated, the change characteristic points are screened and the gas-liquid ratio interval is extracted, the change range and the initial region of phase evolution are marked point by point, and the gas-liquid ratio change characteristic range is generated; S3: Based on the characteristic range of the gas-liquid ratio change, extract the fluid distribution path under the differentiated pressure gradient, combine the pressure and volume parameters to calculate the gas-liquid ratio change rate, screen the distribution area and locate the gas-liquid two-phase transition point, extract the phase segmentation point through the change amplitude, and generate the fluid phase transition critical point data; S4: Based on the fluid phase transition critical point data, call the pressure and volume characteristic range, calculate the influence of the pressure gradient on the gas-liquid ratio change point by point, screen the pressure distribution range and volume value of the transition area, generate the fluid multiphase characteristic distribution trend by combining the multi-point data, and obtain the phase transition area characteristic data; S5: Based on the characteristic data of the phase transition area, the pressure and gas-liquid ratio distribution ranges are classified and marked, the distribution boundaries and change trends are extracted section by section, the correlation characteristics of the pressure and volume in the multiphase area are summarized, and the distribution states of the gas-liquid two-phase and multiphase areas are generated in combination with the boundary range to generate the fluid phase distribution results.

[0007] As a further scheme of the present invention, the gas-liquid ratio dynamic data set includes pressure parameters, temperature parameters, volume parameters, gas-liquid ratio change values, and time series trend data; the gas-liquid ratio change characteristic range includes the gas-liquid ratio change rate range, pressure change interval, volume change interval, gas-liquid ratio characteristic points, and phase evolution boundaries; the fluid phase transition critical point data includes the gas-liquid two-phase transition point position, phase segmentation point parameters, pressure gradient interval, and volume characteristic interval; the phase transition region characteristic data includes transition region pressure characteristics, gas-liquid ratio characteristic interval, multiphase distribution trend, and associated volume characteristics; the fluid phase distribution results include gas-liquid two-phase distribution range, multiphase distribution range, pressure distribution characteristics, volume distribution characteristics, and boundary association characteristics.

[0008] As a further solution of the present invention, based on the multi-point temperature and pressure sampling data of the oil and gas reservoir fluid, the pressure, temperature and volume parameters are extracted, the gas-liquid ratio sensor is called to record the change of the gas-liquid ratio, the pressure and volume data are matched point by point, and the trend of the gas-liquid ratio change is calculated through the time series. The specific steps of generating a gas-liquid ratio dynamic data set are: S101: Based on the multi-point temperature and pressure sampling data of the oil and gas reservoir fluid, extract the pressure, temperature and volume parameters, sort the sampling data in time series, extract and match the pressure and volume parameters point by point, and jointly process them according to time to generate a pressure and volume matching data set; S102: Based on the pressure-volume matching data set, calling the gas-liquid ratio sensor to record the gas-liquid ratio change, calibrating the gas-liquid ratio data to the pressure-volume corresponding point in time series, and synchronously correlating the gas-liquid ratio data with the matching data set to form a gas-liquid ratio change mapping data set; S103: Based on the gas-liquid ratio change mapping data set, extract the gas-liquid ratio change trend data according to the time series, perform correlation analysis using the trend change value and the time parameter, and generate a gas-liquid ratio dynamic data set.

[0009] As a further solution of the present invention, based on the gas-liquid ratio dynamic data set, the gas-liquid ratio change rate is compared with the pressure and volume parameters item by item, the pressure and volume differences are calculated, the change characteristic points are screened and the gas-liquid ratio interval is extracted, and the change range and the initial region of phase evolution are marked point by point. The specific steps of generating the gas-liquid ratio change characteristic range are: S201: Based on the gas-liquid ratio dynamic data set, extract the gas-liquid ratio change rate and pressure and volume parameters point by point, calculate the pressure difference and volume difference of adjacent points, compare the gas-liquid ratio change rate with the pressure and volume difference respectively, associate and annotate the results according to time series, and generate a gas-liquid ratio change comparison result set; S202: Based on the gas-liquid ratio change comparison result set, extract the gas-liquid ratio change rate and the pressure and volume difference, analyze the associated feature points, extract the gas-liquid ratio interval and the pressure and volume parameters of the feature points point by point, mark the feature range values ​​in the extraction order, and generate a gas-liquid ratio change feature point set; S203: Based on the gas-liquid ratio change feature point set, extract the change range of the gas-liquid ratio interval corresponding to the feature points in sequence, combine the gas-liquid ratio change range with the pressure volume parameters of the feature points, define the initial area and mark the position, and generate the gas-liquid ratio change feature range.

[0010] As a further solution of the present invention, based on the characteristic range of the gas-liquid ratio change, the fluid distribution path under the differentiated pressure gradient is extracted, the pressure and volume parameters are combined to calculate the gas-liquid ratio change rate, the distribution area is screened and the gas-liquid two-phase transition point is located, and the phase segmentation point is extracted by the change amplitude. The specific steps of generating the fluid phase transition critical point data are as follows: S301: extracting the fluid distribution path corresponding to the differential pressure gradient based on the characteristic range of the gas-liquid ratio change, associating the pressure gradient value with the fluid position, extracting the fluid distribution position according to the pressure gradient area, and classifying the path, sorting the path classification results by area and completing the mapping, and generating a fluid distribution path data set; S302: Based on the fluid distribution path data set, extract the pressure and volume parameters and combine them point by point, calculate the gas-liquid ratio change rate, classify the change rate by path, and associate and match it with the pressure and volume parameters, screen the path areas with large differences in the gas-liquid ratio change rate and calibrate the distribution position, and generate the gas-liquid two-phase transition point positioning result; S303: Based on the positioning result of the gas-liquid two-phase transition point, the numerical range of the area with significant difference in change rate is extracted item by item, and the change amplitude in the area is calculated by combining the pressure and volume parameters. The amplitude change point is calibrated as the phase separation point of the gas-liquid two phases and the position is marked to generate the fluid phase transition critical point data.

[0011] As a further solution of the present invention, the gas-liquid ratio change rate calculation formula is specifically: ; in, represents the rate of change of gas-liquid ratio, Represents the pressure difference at adjacent time points, Represents the volume difference between adjacent time points, represents the time interval between adjacent time points, and represent the reference pressure and reference volume respectively.

[0012] As a further solution of the present invention, based on the fluid phase transition critical point data, the pressure and volume characteristic ranges are called, the influence of the pressure gradient on the gas-liquid ratio change is calculated point by point, the pressure distribution range and volume value of the transition area are screened, and the multi-phase characteristic distribution trend of the fluid is generated by combining multi-point data. The specific steps of obtaining the phase transition area characteristic data are as follows: S401: Based on the fluid phase transition critical point data, extract the pressure and volume characteristic range, classify the gas-liquid ratio data point by point according to the pressure gradient, extract the corresponding values ​​of the volume parameter and the pressure change, associate the pressure and volume data according to the time series, and generate a pressure-volume characteristic matching data set; S402: Based on the pressure-volume characteristic matching data set, calculate the influence degree of the pressure gradient on the gas-liquid ratio change, associate the pressure gradient change with the gas-liquid ratio rate, screen the transition area with a large difference between the pressure gradient change and the gas-liquid ratio, locate the pressure distribution range and map the volume value, and generate the pressure volume distribution result of the transition area; S403: Based on the pressure-volume distribution results of the transition area, extract the multi-point trend data of the gas-liquid ratio change, calculate the multi-phase characteristic distribution trend in combination with the distribution law of pressure and volume, integrate the gas-liquid ratio change trend and position characteristic data by region, and obtain the phase transition area characteristic data.

[0013] As a further solution of the present invention, the calculation formula for the influence degree of the pressure gradient on the change of the gas-liquid ratio is specifically: ; in, Represents the influence of pressure gradient on the change of gas-liquid ratio. Represents the pressure change value at adjacent time points, Represents the volume value at the corresponding time point, represents the time interval between adjacent time points, Represents the gas-liquid ratio at the corresponding time point.

[0014] As a further solution of the present invention, based on the characteristic data of the phase transition region, the pressure and gas-liquid ratio distribution ranges are classified and marked, the distribution boundaries and change trends are extracted section by section, the correlation characteristics of the pressure and volume in the multiphase region are summarized, and the gas-liquid two-phase and multiphase region distribution states are generated in combination with the boundary range. The specific steps of generating the fluid phase distribution result are as follows: S501: Based on the phase transition region characteristic data, the pressure and gas-liquid ratio distribution ranges are classified and marked, the pressure data and gas-liquid ratio values ​​are segmented by region, the upper and lower limits of the distribution range are extracted item by item and the regions are marked, the extraction results are integrated and the classification mapping is completed, and the pressure gas-liquid ratio distribution classification data is generated; S502: Based on the pressure gas-liquid ratio distribution classification data, extract the distribution boundary and change trend of each area, associate the boundary position with the gas-liquid ratio change trend according to the pressure range, partition and sort the pressure and volume parameters of the multiphase area, extract the associated parameters and calibrate the boundary area characteristics, and generate the multiphase area boundary and associated characteristic data; S503: Based on the multiphase region boundary and associated characteristic data, the pressure and volume distribution law of the multiphase region is extracted, and the distribution characteristics of the gas-liquid two-phase and multiphase regions are summarized section by section in combination with the boundary position data. The summarized results are integrated and the regional state data is output to obtain the fluid phase distribution result.

[0015] A phase state detection system for oil and gas reservoir fluid, comprising: The data acquisition module extracts pressure, temperature and volume parameters based on multi-point temperature and pressure sampling data of oil and gas reservoir fluids, calls the gas-liquid ratio sensor to record the change of gas-liquid ratio, calculates the trend of gas-liquid ratio change through time series, and generates a dynamic data set of gas-liquid ratio; The characteristic analysis module compares the gas-liquid ratio change rate with the pressure and volume parameters item by item based on the gas-liquid ratio dynamic data set, calculates the pressure and volume difference, marks the change range and the initial region of phase evolution point by point, and generates the gas-liquid ratio change characteristic range; The path identification module extracts the fluid distribution path under the differential pressure gradient based on the gas-liquid ratio change characteristic range, combines the pressure and volume parameters to calculate the gas-liquid ratio change rate, extracts the phase segmentation point through the change amplitude, and generates the fluid phase transition critical point data; The dynamic trend module calls the pressure and volume characteristic range based on the fluid phase transition critical point data, calculates the influence of the pressure gradient on the gas-liquid ratio change point by point, generates the fluid multiphase characteristic distribution trend by combining the multi-point data, and obtains the phase transition area characteristic data; The result marking module classifies and marks the pressure and gas-liquid ratio distribution range based on the phase transition region characteristic data, extracts the distribution boundaries and change trends section by section, generates the gas-liquid two-phase and multi-phase regional distribution states based on the boundary range, and generates the fluid phase distribution results.

[0016] Compared with the prior art, the advantages and positive effects of the present invention are: In the present invention, various data are extracted through temperature and pressure sampling, and the gas-liquid ratio is recorded in combination with a gas-liquid ratio sensor, so as to improve the multi-dimensional monitoring capability of the fluid state. By comparing the gas-liquid ratio change rate with the pressure and volume parameters, the analytical depth of the gas-liquid ratio change law is enhanced. By combining the pressure gradient and volume characteristics, the identification of the multiphase region boundary under complex environment is optimized. Through the correlation analysis of the pressure gradient and the gas-liquid ratio data, the gas-liquid two-phase and multi-phase region states are characterized, which provides comprehensive support for the dynamic monitoring and phase distribution analysis of oil and gas reservoir fluids. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the following briefly introduces the drawings required for use in the description of the embodiments. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without creative work.

[0018] Figure 1 It is a schematic diagram of the steps of the present invention; Figure 2 is a flow chart of the steps of S1 of the present invention; Figure 3 is a flow chart of the steps of S2 of the present invention; Figure 4 is a flow chart of the steps of S3 of the present invention; Figure 5 is a flow chart of the steps of S4 of the present invention; Figure 6 is a flow chart of the steps of S5 of the present invention; Figure 7 It is a system module diagram of the present invention. DETAILED DESCRIPTION

[0019] The technical solution of the present invention is described below in conjunction with the accompanying drawings.

[0020] In the embodiments of the present invention, words such as "exemplarily" and "for example" are used to indicate examples, illustrations or explanations. Any embodiment or design described as "example" in the present invention should not be interpreted as being more preferred or more advantageous than other embodiments or designs. Specifically, the use of the word "example" is intended to present the concept in a specific way. In addition, in the embodiments of the present invention, the meaning expressed by "and / or" can be both, or it can be either of the two.

[0021] In the embodiments of the present invention, "image" and "picture" can sometimes be used interchangeably. It should be noted that when the difference between them is not emphasized, the meanings they intend to express are the same. "of", "corresponding, relevant" and "corresponding" can sometimes be used interchangeably. It should be noted that when the difference between them is not emphasized, the meanings they intend to express are the same.

[0022] In the embodiments of the present invention, sometimes a subscript such as W1 may be written as a non-subscript such as W1. When the difference is not emphasized, the meanings to be expressed are the same.

[0023] In order to make the technical problems, technical solutions and advantages to be solved by the present invention more clear, a detailed description will be given below with reference to the accompanying drawings and specific embodiments.

[0024] See also Figure 1 , a phase state detection method for oil and gas reservoir fluid, comprising the following steps: S1: Based on the multi-point temperature and pressure sampling data of oil and gas reservoir fluids, extract the pressure, temperature and volume parameters, call the gas-liquid ratio sensor to record the change of gas-liquid ratio, match the pressure and volume data point by point, calculate the change trend of gas-liquid ratio through time series, and generate a dynamic data set of gas-liquid ratio; S2: Based on the dynamic data set of gas-liquid ratio, the gas-liquid ratio change rate is compared with the pressure and volume parameters item by item, the pressure and volume differences are calculated, the change characteristic points are screened and the gas-liquid ratio interval is extracted, the change range and the initial area of ​​phase evolution are marked point by point, and the gas-liquid ratio change characteristic range is generated; S3: Based on the characteristic range of gas-liquid ratio change, the fluid distribution path under differentiated pressure gradient is extracted, the pressure and volume parameters are combined to calculate the gas-liquid ratio change rate, the distribution area is screened and the gas-liquid two-phase transition point is located, the phase segmentation point is extracted by the change amplitude, and the fluid phase transition critical point data is generated; S4: Based on the critical point data of fluid phase transition, call the pressure and volume characteristic range, calculate the influence of pressure gradient on gas-liquid ratio change point by point, screen the pressure distribution range and volume value of the transition area, combine multi-point data to generate the fluid multiphase characteristic distribution trend, and obtain the characteristic data of the phase transition area; S5: Based on the characteristic data of the phase transition area, the pressure and gas-liquid ratio distribution ranges are classified and marked, the distribution boundaries and change trends are extracted segment by segment, the correlation characteristics of pressure and volume in the multiphase area are summarized, and the distribution states of the gas-liquid two-phase and multiphase areas are generated in combination with the boundary range to generate the fluid phase distribution results.

[0025] The dynamic data set of gas-liquid ratio includes pressure parameters, temperature parameters, volume parameters, gas-liquid ratio change values, and time series trend data. The characteristic range of gas-liquid ratio change includes the gas-liquid ratio change rate range, pressure change interval, volume change interval, gas-liquid ratio characteristic points, and phase evolution boundary. The critical point data of fluid phase conversion includes the position of gas-liquid two-phase conversion point, phase segmentation point parameters, pressure gradient interval, and volume characteristic interval. The characteristic data of phase conversion area include transition area pressure characteristics, gas-liquid ratio characteristic interval, multiphase distribution trend, and associated volume characteristics. The fluid phase distribution results include gas-liquid two-phase distribution range, multiphase distribution range, pressure distribution characteristics, volume distribution characteristics, and boundary association characteristics.

[0026] See also Figure 2 , the specific steps of S1 are: S101: Based on the multi-point temperature and pressure sampling data of the oil and gas reservoir fluid, extract the pressure, temperature and volume parameters, sort the sampling data in time series, extract and match the pressure and volume parameters point by point, and jointly process them according to time to generate a pressure and volume matching data set; The temperature, pressure and volume parameters are obtained through dedicated temperature and pressure sampling equipment, the data are sorted according to the time axis for different sampling points, the pressure and volume parameters are extracted point by point and a time series is established, the temperature and pressure data output by the temperature and pressure sensor are jointly processed with the volume data output by the volumetric flow meter, and the pressure and volume parameters at different time points are matched through the interpolation algorithm to generate a matching pressure and volume data set.

[0027] S102: Based on the pressure-volume matching data set, call the gas-liquid ratio sensor to record the gas-liquid ratio change, calibrate the gas-liquid ratio data to the pressure-volume corresponding point in time series, and synchronously associate the gas-liquid ratio data with the matching data set to form a gas-liquid ratio change mapping data set; The gas-liquid ratio data is calibrated to the corresponding points of pressure and volume in time series, according to the formula ; Calculate the gas-liquid ratio; In the formula, represents the gas-liquid ratio, Represents pressure, represents volume, is the gas deviation factor, is the gas constant, For temperature.

[0028] The gas-liquid ratio formula is derived from the gas state equation, and the gas-liquid ratio is calculated by combining the pressure-volume matching data set in actual operation and the real-time temperature recorded by the temperature sensor. The pressure value P is collected in real time by the pressure sensor in Pascals, the volume V is measured by the flow meter in cubic meters, the gas deviation factor Z is obtained through experimental correction and obtained by the interpolation method of the calibration table, the temperature T is in Kelvin, and the gas constant The value is 8.314 J / (mol·K).

[0029] Example calculation: Assume that the pressure P collected at a certain moment is 1.5×10 6 Pa, volume V is 0.02m 3 , Z is 0.95, T is 298K, calculate the gas-liquid ratio: ; calculate: ; The result shows that the gas-liquid ratio at the corresponding pressure-volume matching point is 12.72, which means that the ratio of the moles of gas to the moles of liquid is 12.72, and is further used to form a gas-liquid ratio change mapping data set.

[0030] S103: based on the gas-liquid ratio change mapping data set, extracting the gas-liquid ratio change trend data according to the time series, performing correlation analysis using the trend change value and the time parameter, and generating a gas-liquid ratio dynamic data set; The gas-liquid ratio values ​​at different time points in the time series are extracted, and the gas-liquid ratio change rate is calculated using the numerical derivative method. The change rate is used as the basis of the gas-liquid ratio trend data. The dynamic characteristics of the gas-liquid ratio changing with time are extracted by analyzing the data associated with the time points. The trend change values ​​are fitted through a group of differential equations, and finally a gas-liquid ratio dynamic data set is generated.

[0031] See also Figure 3 , the specific steps of S2 are: S201: Based on the gas-liquid ratio dynamic data set, extract the gas-liquid ratio change rate and pressure and volume parameters point by point, calculate the pressure difference and volume difference of adjacent points, compare the gas-liquid ratio change rate with the pressure and volume difference respectively, associate and annotate the results according to the time series, and generate a gas-liquid ratio change comparison result set; The rate of change of the gas-liquid ratio is calculated by the numerical derivative method, and the collected pressure data is differentially processed to obtain the pressure difference between adjacent points. At the same time, the volume data is differentially calculated to obtain the volume difference. The pressure difference and volume difference are compared respectively in combination with the gas-liquid ratio change rate. The pressure, volume and gas-liquid ratio change rate data are correlated through time series. The data points after comparison and correlation are marked according to the set labeling rules, and finally a gas-liquid ratio change comparison result set is generated.

[0032] S202: based on the gas-liquid ratio change comparison result set, extract the gas-liquid ratio change rate and the pressure and volume difference, analyze the associated feature points, extract the gas-liquid ratio interval and the pressure and volume parameters of the feature points point by point, mark the feature range values ​​according to the extraction order, and generate a gas-liquid ratio change feature point set; The gas-liquid ratio change rate and the pressure and volume difference are analyzed for characteristic points. According to the formula ; Calculate the correlation eigenvalue; In the formula, represents the eigenvalue, Represents the pressure difference, Represents the volume difference.

[0033] The characteristic value calculation formula combines the square sum of the pressure difference and the volume difference to measure the effect of pressure and volume changes on the gas-liquid ratio. Obtained by differential time series data recorded by the pressure sensor, in Pascals, volume difference It is obtained by differentiating the volume data recorded by the flow meter, and the unit is cubic meter. Then the equivalent coefficient k is introduced to make the dimensions of k⋅ΔV and ΔP consistent, but the equivalent coefficient k does not change the value of ΔV, and the unit of F is also Pascal.

[0034] Example calculation: If the pressures at two adjacent points are and , the volumes are and ,but: ; ; Plug into the formula: ; ; ; The results show that the comprehensive characteristics of the pressure and volume difference corresponding to the feature point are , which is used for the subsequent extraction of the gas-liquid ratio interval, pressure and volume parameters of the feature points.

[0035] S203: based on the gas-liquid ratio change feature point set, sequentially extract the change range of the gas-liquid ratio interval corresponding to the feature points, combine the gas-liquid ratio change range with the pressure volume parameters of the feature points, delineate the initial area and mark the position, and generate the gas-liquid ratio change feature range; The variation range of the gas-liquid ratio interval of the extracted feature points is analyzed. The difference between the maximum and minimum values ​​of the gas-liquid ratio interval in the time series is calculated to obtain the variation range. The variation range is spatially delineated in combination with the pressure volume feature point parameters, and the delineated area is marked in a time- and space-related manner to finally generate the gas-liquid ratio variation characteristic range.

[0036] See also Figure 4 , the specific steps of S3 are: S301: based on the characteristic range of gas-liquid ratio change, extract the fluid distribution path corresponding to the differentiated pressure gradient, associate the pressure gradient value with the fluid position, extract the fluid distribution position according to the pressure gradient area, and classify the path, sort the path classification results by area and complete the mapping, and generate a fluid distribution path data set; By extracting differentiated pressure gradient data, the change value of the pressure gradient is associated with the position data of the fluid in the time series point by point, and the differential calculation method is used to obtain the distribution range and direction of the pressure gradient. The pressure gradient value is divided into regions and marked with specific ranges. The fluid position distribution in each region is classified and sorted according to the characteristic values ​​of the fluid path. The path mapping is completed through the correlation matrix between the paths, and finally a fluid distribution path dataset is generated.

[0037] S302: Based on the fluid distribution path data set, extract the pressure and volume parameters and combine them point by point, calculate the gas-liquid ratio change rate, classify the change rate by path, and associate and match it with the pressure and volume parameters, select the path area with large difference in gas-liquid ratio change rate and calibrate the distribution position, and generate the gas-liquid two-phase transition point positioning result; The specific calculation formula for the gas-liquid ratio change rate is: ; in, represents the rate of change of gas-liquid ratio, Represents the pressure difference at adjacent time points, Represents the volume difference between adjacent time points, represents the time interval between adjacent time points, and represent the reference pressure and reference volume respectively.

[0038] Given: Initial pressure , end pressure , pressure change , volume change , time interval ; Calculate the normalized rate of change: Assume the reference pressure , assuming the reference volume ; Calculate the normalized pressure rate of change: ; Calculate the normalized volume change rate: ; Calculate the final rate: ; ; The result shows that the gas-liquid ratio change rate is 0.0353, which is used as a parameter to evaluate the gas-liquid ratio change amplitude in the path when used for path classification. The numerical results are closely related to the path classification and matching pressure and volume parameters in the steps, providing a quantitative basis for screening out path areas with large differences in gas-liquid ratio change rates, and calibrating the specific distribution locations.

[0039] S303: Based on the positioning result of the gas-liquid two-phase transition point, the numerical range of the area with significant difference in change rate is extracted item by item, and the change amplitude in the area is calculated by combining the pressure and volume parameters. The amplitude change point is marked as the phase separation point of the gas-liquid two phases and the position is marked to generate the fluid phase transition critical point data; The pressure and volume parameters are jointly processed to calculate the change amplitude of the gas-liquid ratio in the area point by point. The amplitude change value of each point is obtained by the difference calculation method, and the spatial coordinates of the change points are calibrated. The points with significant amplitude changes are calibrated as the phase separation points of the gas and liquid phases. The critical points of fluid phase transition are marked by constructing spatial position mapping, and finally the critical point data of fluid phase transition are generated.

[0040] See also Figure 5 , the specific steps of S4 are: S401: Based on the fluid phase transition critical point data, extract the pressure and volume characteristic range, classify the gas-liquid ratio data point by point according to the pressure gradient, extract the corresponding values ​​of the volume parameter and the pressure change, associate the pressure and volume data according to the time series, and generate a pressure-volume characteristic matching data set; The classification rules of gas-liquid ratio data are divided by pressure gradient. The differential values ​​of time series pressure data and volume data collected by pressure sensors are respectively calculated to obtain the change law. The pressure and volume parameters are associated point by point according to the time series. The classified gas-liquid ratio data are matched with the pressure and volume data of the time series item by item, and finally a pressure-volume characteristic matching data set is generated.

[0041] S402: Based on the pressure-volume characteristic matching data set, calculate the influence of the pressure gradient on the gas-liquid ratio change, associate the pressure gradient change with the gas-liquid ratio rate, screen the transition area with large difference between the pressure gradient change and the gas-liquid ratio, locate the pressure distribution range and map the volume value, and generate the pressure volume distribution result of the transition area; The specific calculation formula for the influence of pressure gradient on the change of gas-liquid ratio is: ; in, Represents the influence of pressure gradient on the change of gas-liquid ratio. Represents the pressure change value at adjacent time points, Represents the volume value at the corresponding time point, represents the time interval between adjacent time points, Represents the gas-liquid ratio at the corresponding time point.

[0042] Calculation process: Set a set of sampling data: pressure value from Pascal reduced to Pascal, volume is 0.04 cubic meters, gas-liquid ratio is 12, and time interval is 5 seconds.

[0043] Calculate the pressure change: ; Determine the volume parameters: ; Determine the gas-liquid ratio: ; Determine the time interval: ; Enter the formula to calculate: ; Calculate the numerator: ; Calculate the denominator: ; Calculate the impact value: ; The results show that the impact value is 200 Pa·m3 / s, which represents the comprehensive change intensity under the current pressure gradient change and gas-liquid ratio rate conditions. This value is used to further screen the areas with large differences in pressure gradient change and gas-liquid ratio in the transition region, and provide basic data support for locating the pressure distribution range.

[0044] S403: Based on the pressure volume distribution results of the transition area, extract the multi-point trend data of the gas-liquid ratio change, calculate the multi-phase characteristic distribution trend by combining the distribution law of pressure and volume, integrate the gas-liquid ratio change trend and position characteristic data by region, and obtain the phase transition area characteristic data; By extracting the gas-liquid ratio change trend data point by point, the multi-point interpolation method is used to calculate the distribution law of pressure and volume in the time series, the change amplitude of pressure and volume parameters in different regions is correlated and analyzed, the gas-liquid ratio change trend and position characteristic parameters in the region are integrated, and a multiphase distribution model is constructed. Finally, the characteristic data of the phase transition area is obtained and the regional range is calibrated.

[0045] See also Figure 6 , the specific steps of S5 are: S501: Based on the phase transition region characteristic data, the pressure and gas-liquid ratio distribution ranges are classified and marked, the pressure data and gas-liquid ratio values ​​are segmented by region, the upper and lower limits of the distribution range are extracted item by item and the regions are marked, the extraction results are integrated and the classification mapping is completed, and the pressure gas-liquid ratio distribution classification data is generated; The pressure sensor and gas-liquid ratio data are processed in sections by region. The range interval is determined by calculating the upper and lower limits of each distribution range. The pressure data and gas-liquid ratio values ​​in different regions are segmented and associated. The upper and lower limit data of each region are uniformly marked and integrated. The pressure gas-liquid ratio distribution classification data is finally generated by constructing a segmented mapping relationship.

[0046] S502: Based on the pressure gas-liquid ratio distribution classification data, the distribution boundary and change trend of each region are extracted, the boundary position is associated with the gas-liquid ratio change trend according to the pressure range, the pressure and volume parameters of the multiphase region are partitioned and sorted, the associated parameters are extracted and the boundary region characteristics are calibrated, and the multiphase region boundary and associated characteristic data are generated; Extract the distribution boundaries and change trends of each region, according to the formula ; Calculate the correlation characteristics of the boundary area; In the formula, represents the boundary-related characteristic value, and are the upper and lower pressure limits of the boundary, is the rate at which the gas-liquid ratio changes with pressure, For volume.

[0047] formula: ; in: (rate of change of gas-liquid ratio with pressure): the unit should be , (Volume): The unit is , (Pressure change): The unit is .

[0048] Therefore, the unit after integral calculation is: ; That is, the unit of E should be , represents the volume rate of change of gas-liquid ratio.

[0049] Recalculate E: Pressure Range: Lower limit ; Upper limit ; Gas-liquid ratio change rate : set up exist Place ; set up exist Chuwei ; Using a linear change model: ; Solve a and b through known points: ; ; volume ; Calculate the change equation of the gas-liquid ratio change rate: Solve the system of equations: ; ; ; Find b: ; ; ; so: ; Compute the integral: ; ; Calculate the first part: ; ; ; ; ; Multiply : ; Calculate the second part: ; ; Multiply : ; Sum: ; Multiply by volume : ; ; Calculation results: Corrected boundary relationship characteristic value .

[0050] This unit represents the volume rate of change of the gas-liquid ratio, that is, how the change of the gas-liquid ratio affects the volume flow in the area.

[0051] Summary of calculation steps Set pressure range , , given The changing trend of the linear equation is used to solve a and b, and the integral equation is established. , instead of replacing it with a constant, calculating the integral, calculating the item by item and , solve the final boundary relationship characteristic value , and check the unit.

[0052] After correction, the boundary characteristic value , used to calibrate the characteristics of the region and generate multi-phase region boundaries and associated characteristic data.

[0053] S503: Based on the multiphase region boundary and associated characteristic data, the pressure and volume distribution law of the multiphase region is extracted, and the distribution characteristics of the gas-liquid two-phase and multiphase regions are summarized section by section in combination with the boundary position data, and the summarized results are integrated and output as regional state data to obtain the fluid phase distribution result; The gradient change analysis method is used to summarize the distribution characteristics of gas-liquid two-phase and multi-phase regions. The pressure, volume and gas-liquid ratio correlation data of each region are calculated segmentally, and the distribution characteristics in each region are integrated to form a multi-phase regional distribution law model. The model is then combined with the boundary position data for unified output to finally obtain the fluid phase distribution results.

[0054] See also Figure 7 , a phase state detection system for oil and gas reservoir fluid, comprising: The data acquisition module extracts pressure, temperature and volume parameters based on multi-point temperature and pressure sampling data of oil and gas reservoir fluids, calls the gas-liquid ratio sensor to record the change of gas-liquid ratio, calculates the trend of gas-liquid ratio change through time series, and generates a dynamic data set of gas-liquid ratio; Based on the dynamic data set of gas-liquid ratio, the characteristic analysis module compares the gas-liquid ratio change rate with the pressure and volume parameters item by item, calculates the pressure and volume difference, marks the change range and the initial area of ​​phase evolution point by point, and generates the characteristic range of gas-liquid ratio change; The path identification module extracts the fluid distribution path under the differential pressure gradient based on the characteristic range of gas-liquid ratio change, combines the pressure and volume parameters to calculate the gas-liquid ratio change rate, extracts the phase split point through the change amplitude, and generates the fluid phase transition critical point data; The dynamic trend module uses the pressure and volume characteristic range based on the fluid phase transition critical point data, calculates the influence of pressure gradient on the gas-liquid ratio change point by point, generates the fluid multiphase characteristic distribution trend by combining multi-point data, and obtains the phase transition area characteristic data; The result marking module classifies and marks the pressure and gas-liquid ratio distribution range based on the phase transition region characteristic data, extracts the distribution boundaries and change trends segment by segment, generates the gas-liquid two-phase and multi-phase regional distribution states based on the boundary range, and generates the fluid phase distribution results.

[0055] The above is only a specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Any person skilled in the art can easily think of changes or substitutions within the technical scope disclosed by the present invention, which should be included in the protection scope of the present invention. Therefore, the protection scope of the present invention should be based on the protection scope of the claims.

Claims

1. A method for detecting the phase state of oil and gas reservoir fluid, characterized in that: The following steps are involved: S1: Based on the multi-point temperature and pressure sampling data of oil and gas reservoir fluids, extract the pressure, temperature and volume parameters, call the gas-liquid ratio sensor to record the change of gas-liquid ratio, match the pressure and volume data point by point, calculate the change trend of gas-liquid ratio through time series, and generate a dynamic data set of gas-liquid ratio; S2: Based on the gas-liquid ratio dynamic data set, the gas-liquid ratio change rate is compared with the pressure and volume parameters item by item, the pressure and volume differences are calculated, the change characteristic points are screened and the gas-liquid ratio interval is extracted, the change range and the initial region of phase evolution are marked point by point, and the gas-liquid ratio change characteristic range is generated; S3: Based on the characteristic range of the gas-liquid ratio change, extract the fluid distribution path under the differentiated pressure gradient, combine the pressure and volume parameters to calculate the gas-liquid ratio change rate, screen the distribution area and locate the gas-liquid two-phase transition point, extract the phase segmentation point through the change amplitude, and generate the fluid phase transition critical point data; S4: Based on the fluid phase transition critical point data, call the pressure and volume characteristic range, calculate the influence of the pressure gradient on the gas-liquid ratio change point by point, screen the pressure distribution range and volume value of the transition area, generate the fluid multiphase characteristic distribution trend by combining the multi-point data, and obtain the phase transition area characteristic data; S5: Based on the characteristic data of the phase transition area, the pressure and gas-liquid ratio distribution ranges are classified and marked, the distribution boundaries and change trends are extracted section by section, the correlation characteristics of the pressure and volume in the multiphase area are summarized, and the distribution states of the gas-liquid two-phase and multiphase areas are generated in combination with the boundary range to generate the fluid phase distribution results.

2. The phase state detection method of oil and gas reservoir fluid according to claim 1, characterized in that: The gas-liquid ratio dynamic data set includes pressure parameters, temperature parameters, volume parameters, gas-liquid ratio change values, and time series trend data. The gas-liquid ratio change characteristic range includes the gas-liquid ratio change rate range, pressure change interval, volume change interval, gas-liquid ratio characteristic points, and phase evolution boundaries. The fluid phase transition critical point data includes the gas-liquid two-phase transition point position, phase segmentation point parameters, pressure gradient interval, and volume characteristic interval. The phase transition region characteristic data includes transition region pressure characteristics, gas-liquid ratio characteristic interval, multiphase distribution trend, and associated volume characteristics. The fluid phase distribution results include gas-liquid two-phase distribution range, multiphase distribution range, pressure distribution characteristics, volume distribution characteristics, and boundary association characteristics.

3. The phase state detection method of oil and gas reservoir fluid according to claim 1, characterized in that: Based on the multi-point temperature and pressure sampling data of oil and gas reservoir fluids, the pressure, temperature and volume parameters are extracted, the gas-liquid ratio sensor is called to record the change of gas-liquid ratio, the pressure and volume data are matched point by point, and the trend of gas-liquid ratio change is calculated through time series. The specific steps to generate a dynamic data set of gas-liquid ratio are as follows: S101: Based on the multi-point temperature and pressure sampling data of the oil and gas reservoir fluid, extract the pressure, temperature and volume parameters, sort the sampling data in time series, extract and match the pressure and volume parameters point by point, and jointly process them according to time to generate a pressure and volume matching data set; S102: Based on the pressure-volume matching data set, calling the gas-liquid ratio sensor to record the gas-liquid ratio change, calibrating the gas-liquid ratio data to the pressure-volume corresponding point in time series, and synchronously correlating the gas-liquid ratio data with the matching data set to form a gas-liquid ratio change mapping data set; S103: Based on the gas-liquid ratio change mapping data set, extract the gas-liquid ratio change trend data according to the time series, perform correlation analysis using the trend change value and the time parameter, and generate a gas-liquid ratio dynamic data set.

4. The phase state detection method of oil and gas reservoir fluid according to claim 1, characterized in that: Based on the gas-liquid ratio dynamic data set, the gas-liquid ratio change rate is compared with the pressure and volume parameters item by item, the pressure and volume differences are calculated, the change characteristic points are screened and the gas-liquid ratio interval is extracted, and the change range and the initial region of phase evolution are marked point by point. The specific steps for generating the gas-liquid ratio change characteristic range are as follows: S201: Based on the gas-liquid ratio dynamic data set, extract the gas-liquid ratio change rate and pressure and volume parameters point by point, calculate the pressure difference and volume difference of adjacent points, compare the gas-liquid ratio change rate with the pressure and volume difference respectively, associate and annotate the results according to time series, and generate a gas-liquid ratio change comparison result set; S202: Based on the gas-liquid ratio change comparison result set, extract the gas-liquid ratio change rate and the pressure and volume difference, analyze the associated feature points, extract the gas-liquid ratio interval and the pressure and volume parameters of the feature points point by point, mark the feature range values ​​in the extraction order, and generate a gas-liquid ratio change feature point set; S203: Based on the gas-liquid ratio change feature point set, extract the change range of the gas-liquid ratio interval corresponding to the feature points in sequence, combine the gas-liquid ratio change range with the pressure volume parameters of the feature points, define the initial area and mark the position, and generate the gas-liquid ratio change feature range.

5. The phase state detection method of oil and gas reservoir fluid according to claim 1, characterized in that: Based on the characteristic range of the gas-liquid ratio change, the fluid distribution path under the differentiated pressure gradient is extracted, the pressure and volume parameters are combined to calculate the gas-liquid ratio change rate, the distribution area is screened and the gas-liquid two-phase transition point is located, and the phase segmentation point is extracted by the change amplitude. The specific steps of generating the fluid phase transition critical point data are as follows: S301: extracting the fluid distribution path corresponding to the differential pressure gradient based on the characteristic range of the gas-liquid ratio change, associating the pressure gradient value with the fluid position, extracting the fluid distribution position according to the pressure gradient area, and classifying the path, sorting the path classification results by area and completing the mapping, and generating a fluid distribution path data set; S302: Based on the fluid distribution path data set, extract the pressure and volume parameters and combine them point by point, calculate the gas-liquid ratio change rate, classify the change rate by path, and associate and match it with the pressure and volume parameters, screen the path areas with large differences in the gas-liquid ratio change rate and calibrate the distribution position, and generate the gas-liquid two-phase transition point positioning result; S303: Based on the positioning result of the gas-liquid two-phase transition point, the numerical range of the area with significant difference in change rate is extracted item by item, and the change amplitude in the area is calculated by combining the pressure and volume parameters. The amplitude change point is calibrated as the phase separation point of the gas-liquid two phases and the position is marked to generate the fluid phase transition critical point data.

6. The method for phase state detection of oil and gas reservoir fluid according to claim 5, characterized in that: The specific calculation formula of the gas-liquid ratio change rate is: ； in, represents the rate of change of gas-liquid ratio, Represents the pressure difference at adjacent time points, Represents the volume difference between adjacent time points, represents the time interval between adjacent time points, and represent the reference pressure and reference volume respectively.

7. The phase state detection method of oil and gas reservoir fluid according to claim 1, characterized in that: Based on the critical point data of the fluid phase transition, the pressure and volume characteristic ranges are called, the influence of the pressure gradient on the change of the gas-liquid ratio is calculated point by point, the pressure distribution range and volume value of the transition area are screened, and the multi-phase characteristic distribution trend of the fluid is generated by combining multi-point data. The specific steps for obtaining the characteristic data of the phase transition area are as follows: S401: Based on the fluid phase transition critical point data, extract the pressure and volume characteristic range, classify the gas-liquid ratio data point by point according to the pressure gradient, extract the corresponding values ​​of the volume parameter and the pressure change, associate the pressure and volume data according to the time series, and generate a pressure-volume characteristic matching data set; S402: Based on the pressure-volume characteristic matching data set, calculate the influence degree of the pressure gradient on the gas-liquid ratio change, associate the pressure gradient change with the gas-liquid ratio rate, screen the transition area with a large difference between the pressure gradient change and the gas-liquid ratio, locate the pressure distribution range and map the volume value, and generate the pressure volume distribution result of the transition area; S403: Based on the pressure-volume distribution results of the transition area, extract the multi-point trend data of the gas-liquid ratio change, calculate the multi-phase characteristic distribution trend in combination with the distribution law of pressure and volume, integrate the gas-liquid ratio change trend and position characteristic data by region, and obtain the phase transition area characteristic data.

8. The method for phase state detection of oil and gas reservoir fluid according to claim 7, characterized in that: The specific calculation formula for the influence of the pressure gradient on the change of the gas-liquid ratio is: ； in, Represents the influence of pressure gradient on the change of gas-liquid ratio. Represents the pressure change value at adjacent time points, Represents the volume value at the corresponding time point, represents the time interval between adjacent time points, Represents the gas-liquid ratio at the corresponding time point.

9. The phase state detection method of oil and gas reservoir fluid according to claim 1, characterized in that: Based on the characteristic data of the phase transition region, the pressure and gas-liquid ratio distribution ranges are classified and marked, the distribution boundaries and change trends are extracted segment by segment, the correlation characteristics of the pressure and volume in the multiphase region are summarized, and the gas-liquid two-phase and multiphase regional distribution states are generated in combination with the boundary range. The specific steps for generating the fluid phase distribution results are as follows: S501: Based on the phase transition region characteristic data, the pressure and gas-liquid ratio distribution ranges are classified and marked, the pressure data and gas-liquid ratio values ​​are segmented by region, the upper and lower limits of the distribution range are extracted item by item and the regions are marked, the extraction results are integrated and the classification mapping is completed, and the pressure gas-liquid ratio distribution classification data is generated; S502: Based on the pressure gas-liquid ratio distribution classification data, extract the distribution boundary and change trend of each area, associate the boundary position with the gas-liquid ratio change trend according to the pressure range, partition and sort the pressure and volume parameters of the multiphase area, extract the associated parameters and calibrate the boundary area characteristics, and generate the multiphase area boundary and associated characteristic data; S503: Based on the multiphase region boundary and associated characteristic data, the pressure and volume distribution law of the multiphase region is extracted, and the distribution characteristics of the gas-liquid two-phase and multiphase regions are summarized section by section in combination with the boundary position data. The summarized results are integrated and the regional state data is output to obtain the fluid phase distribution result.

10. A phase state detection system for oil and gas reservoir fluid, characterized in that: According to a method for detecting a phase state of an oil and gas reservoir fluid according to any one of claims 1 to 9, the system comprises: The data acquisition module extracts pressure, temperature and volume parameters based on multi-point temperature and pressure sampling data of oil and gas reservoir fluids, calls the gas-liquid ratio sensor to record the change of gas-liquid ratio, calculates the trend of gas-liquid ratio change through time series, and generates a dynamic data set of gas-liquid ratio; The characteristic analysis module compares the gas-liquid ratio change rate with the pressure and volume parameters item by item based on the gas-liquid ratio dynamic data set, calculates the pressure and volume difference, marks the change range and the initial region of phase evolution point by point, and generates the gas-liquid ratio change characteristic range; The path identification module extracts the fluid distribution path under the differential pressure gradient based on the gas-liquid ratio change characteristic range, combines the pressure and volume parameters to calculate the gas-liquid ratio change rate, extracts the phase segmentation point through the change amplitude, and generates the fluid phase transition critical point data; The dynamic trend module calls the pressure and volume characteristic range based on the fluid phase transition critical point data, calculates the influence of the pressure gradient on the gas-liquid ratio change point by point, generates the fluid multiphase characteristic distribution trend by combining the multi-point data, and obtains the phase transition area characteristic data; The result marking module classifies and marks the pressure and gas-liquid ratio distribution range based on the phase transition region characteristic data, extracts the distribution boundaries and change trends section by section, generates the gas-liquid two-phase and multi-phase regional distribution states based on the boundary range, and generates the fluid phase distribution results.

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