A device and method for measuring in-situ fluid parameters and physical properties in shale oil reservoirs

Abstract

This invention relates to the field of fluid parameter and property measurement technology, specifically to an in-situ fluid parameter and property measurement device and method for shale oil reservoirs. The invention utilizes an automatic control device with a control and acquisition module of an in-situ fluid parameter and property measurement system for shale oil reservoirs to conduct experiments and collect experimental data. Further, a compression analysis module obtains the crude oil compressibility coefficient for each experiment; a porosity analysis module measures core porosity using the compressibility coefficient method or the volumetric injection method; a permeability analysis module analyzes the historical local stability of each viscosity to obtain an instability index; fuzzy processing, combined with real-time deviations in differential pressure data, dynamically corrects the viscosity data to obtain a corrected viscosity value, reducing the impact of fluid fluctuations and sensor errors; finally, a steady-state method or pressure pulse decay method is used to obtain permeability, improving the accuracy of permeability and providing more accurate data support for shale oil reservoir analysis.

Description

Technical Field

[0001] This invention relates to the field of fluid and physical property parameter measurement technology, specifically to an in-situ fluid and physical property parameter measurement device and method for shale oil reservoirs. Background Technology

[0002] As an important component of unconventional oil and gas resources, the accurate measurement of fluid and physical properties (such as porosity, permeability, and fluid compressibility) of shale oil reservoirs under in-situ conditions is crucial for reserve assessment and development planning.

[0003] Currently, the principle of liquid porosity measurement is based on the volumetric injection method. This method requires cleaning the residual fluid in the pipeline and also needs to consider the compressibility of the liquid. Because the compressibility coefficient, viscosity and other parameters of the liquid are different under different temperature and pressure environments, and the reservoir itself has very prominent heterogeneity and the energy storage stress and fluid phase separation caused by nanoscale pores, it will cause measurement islands in viscosity data acquisition (i.e., the measured data points are scattered and not typical) and static assumptions (i.e., the dynamic flow of fluid with time as the spatial element is in a static state), resulting in inaccurate permeability calculation results.

[0004] Meanwhile, the measurement medium for liquid-based methods of porosity and permeability is generally a single reagent such as brine or white oil. Since shale reservoirs have different wettability to different fluids, crude oil produced by shale reservoirs is the best saturated reagent to accurately match shale reservoirs. However, crude oil is a complex mixture and its compressibility coefficient cannot be directly looked up, resulting in the lack of basic parameters for subsequent porosity and permeability calculations, which restricts the accuracy of reserve assessment. Summary of the Invention

[0005] To address the limitation of existing measurement technologies in accurately acquiring key fluid parameters under realistically simulated formation temperature and pressure conditions, using formation crude oil as the medium, and thus hindering the precise evaluation of shale oil reservoirs, this invention aims to provide an in-situ fluid parameter and property measurement device and method for shale oil reservoirs. The specific technical solution adopted is as follows:

[0006] A device for measuring in-situ fluid parameters and physical properties of shale oil reservoirs includes a device body and a system for measuring in-situ fluid parameters and physical properties of shale oil reservoirs, used to control the device to perform parameter measurements, including a control and acquisition module, a compression analysis module, a pore analysis module, and a permeability analysis module;

[0007] The control and data acquisition module is used to automatically control the device to conduct experiments and acquire experimental data based on a preset experimental program.

[0008] The compression analysis module is used to obtain the crude oil compression coefficient based on the experimental data from each experiment.

[0009] The porosity analysis module is used to measure the core porosity using the compressibility coefficient method based on the experimental data and the crude oil compressibility coefficient.

[0010] The permeability analysis module is used to extract viscosity and pressure difference data from the experimental data; analyze the fluctuation stability of viscosity data within a preset historical neighborhood for each viscosity data point to obtain an instability index for each viscosity data point; process the instability index based on fuzzy logic and combine it with the deviation of the pressure difference data at the same moment to obtain a viscosity calibration confidence level; fuse the viscosity data at each moment with the previous moment based on the viscosity calibration confidence level to obtain a corrected viscosity value; and measure the permeability using a steady-state method based on the corrected viscosity value and the experimental data.

[0011] Furthermore, the method for obtaining the crude oil compressibility coefficient in the in-situ fluid parameter and physical property measurement system for shale oil reservoirs includes:

[0012] With a fixed initial pore fluid pressure and a fixed pressure change, all preset temperatures are iterated one by one. In each experiment, the initial pore fluid pressure and the crude oil compressibility coefficient under the corresponding temperature conditions are obtained based on the liquid volume change before and after the pressure increase. The crude oil compressibility coefficient under different temperature and pressure conditions is obtained by changing the initial pore fluid pressure.

[0013] Furthermore, the method for calculating the compressibility coefficient of crude oil in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes:

[0014] In each experiment, the change in liquid volume before and after the pressure increase is taken as the numerator, the product of the pressure change and the initial total volume of the liquid is taken as the denominator, and the ratio of the fractions is taken as the corresponding crude oil compressibility coefficient.

[0015] Furthermore, the method for obtaining the core porosity in the in-situ fluid parameter and physical property measurement system for shale oil reservoirs includes:

[0016] In each experiment, the equivalent volume is obtained based on the change in liquid volume and pressure before and after the pressure increase, combined with the corresponding crude oil compressibility coefficient; the core porosity of the core sample is obtained based on the difference between the equivalent volume and the total liquid volume of the pump and pipeline, combined with the core sample volume.

[0017] Furthermore, the method for obtaining the equivalent volume in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes:

[0018] The change in liquid volume before and after the pressure increase is taken as the numerator, and the product of the pressure change and the corresponding crude oil compressibility coefficient is taken as the denominator. The ratio of the fractions is taken as the equivalent volume of the corresponding experiment.

[0019] Furthermore, the method for obtaining the instability index in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes:

[0020] For each viscosity data, the CUSUM change point detection algorithm is used to obtain change points in the viscosity data sequence within the preset historical neighborhood, and the viscosity data sequence is divided into subsequences based on the change points; according to the stability of viscosity fluctuations in all subsequences, combined with the number of change points, the instability index corresponding to the viscosity data is obtained.

[0021] Furthermore, the method for obtaining the viscosity calibration confidence level in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes:

[0022] The initial confidence level of the instability index is assessed based on fuzzy logic; the difference between the differential pressure data at each moment and the preset differential pressure value is mapped through a preset attenuation function and used as the attenuation factor;

[0023] By fusing the initial confidence level and the attenuation factor corresponding to the viscosity data at each time point, the viscosity calibration confidence level is obtained.

[0024] Furthermore, the method for obtaining the corrected viscosity value in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes:

[0025] The viscosity data at the same time moment are weighted by the viscosity calibration confidence level at each time moment, and the difference between constant 1 and the viscosity calibration confidence level is used to weight the viscosity data at the previous time moment. The weighted sum is used as the corrected viscosity value at each time moment.

[0026] Furthermore, the method for obtaining the permeability in the in-situ fluid parameter and physical property measurement system for shale oil reservoirs includes:

[0027] In each experiment, the steady-state method based on Darcy's law is used to process the corrected viscosity value, core length, liquid flow rate, core cross-sectional area, and pressure difference between the core injection end and the receiving end at the current moment to obtain the permeability under the corresponding high temperature and high pressure conditions.

[0028] The present invention also proposes a method for measuring in-situ fluid parameters and physical properties of shale oil reservoirs, the method comprising:

[0029] Experiments are conducted and experimental data is collected using an automatic control device based on a preset experimental procedure;

[0030] The crude oil compressibility coefficient is obtained based on the experimental data from each experiment;

[0031] Based on the experimental data and the crude oil compressibility coefficient, the core porosity was measured using the compressibility coefficient method.

[0032] Viscosity and pressure difference data are extracted from the experimental data; the stability of viscosity fluctuations is analyzed within a preset historical neighborhood of each viscosity data point to obtain an instability index for each viscosity data point; the instability index is processed based on fuzzy logic, and combined with the deviation of the pressure difference data at the same moment to obtain a viscosity calibration confidence level; the viscosity data at each moment is fused with the previous moment based on the viscosity calibration confidence level to obtain a corrected viscosity value; the permeability is measured using a steady-state method based on the corrected viscosity value and the experimental data.

[0033] This invention also proposes a method for measuring core porosity based on volumetric injection, the method comprising:

[0034] Experiments are conducted and experimental data is collected using an automatic control device based on a preset experimental procedure;

[0035] The formulas for calculating core porosity include: ;

[0036] In the formula, Core porosity represents the proportion of pore volume to total volume in a core sample and is dimensionless. This represents the pore volume of the rock core. This indicates the total volume of the core sample, expressed in ml.

[0037] Furthermore, methods for obtaining the pore volume of the core include:

[0038] ;

[0039] In the formula: This refers to the pore volume of a rock core, that is, the total volume of all pore spaces inside the core, expressed in ml. This represents the volume of liquid inside the first constant-speed, constant-pressure pump in the initial state. This indicates the volume of liquid inside the first constant-speed, constant-pressure pump in the final state, in ml. This indicates the pore volume of the injection end pipeline, in ml.

[0040] This invention also proposes a method for measuring permeability based on the pressure pulse attenuation method, the method comprising:

[0041] Experiments are conducted and experimental data is collected using an automatic control device based on a preset experimental procedure;

[0042] Viscosity and pressure difference data are extracted from the experimental data; the stability of viscosity fluctuations is analyzed within a preset historical neighborhood of each viscosity data point to obtain an instability index for each viscosity data point; the instability index is processed based on fuzzy logic, and combined with the deviation of the pressure difference data at the same moment to obtain a viscosity calibration confidence level; the viscosity data at each moment is fused with the previous moment based on the viscosity calibration confidence level to obtain a corrected viscosity value; the permeability is measured using the pressure pulse decay method based on the corrected viscosity value and the experimental data.

[0043] Furthermore, the calculation formula for permeability based on the corrected viscosity value and the experimental data using the pressure pulse decay method includes:

[0044] ;

[0045] In the formula, Permeability is the ability of a rock core to allow fluid to pass through it, and is measured in millidarcy mD. This is the improved viscosity value at the current acquisition time, in Pascals per second. The core length represents the length of the fluid flow path within the core, measured in meters (m). The cross-sectional area of ​​the rock core represents the cross-sectional area of ​​the fluid flow, with units of 1000 m². , This is the pressure decay constant, specifically taken as the reciprocal of the unit of seconds, with units of 1 / s. The compressibility coefficient of a fluid represents the relative rate of change of fluid volume under a unit change in pressure. The volume of the injection end reference chamber, The volume of the receiving reference chamber is in ml.

[0046] The present invention has the following beneficial effects:

[0047] This invention utilizes an automatic control device in the control and acquisition module of an in-situ fluid parameter and property measurement system for shale oil reservoirs to conduct experiments and collect experimental data, providing a data foundation for subsequent module analysis. Furthermore, a compression analysis module obtains the crude oil compressibility coefficient for each experiment, providing data support for accurate analysis of porosity and permeability. A porosity analysis module measures core porosity using the compressibility coefficient method, eliminating the need for pipeline cleaning, or employs a volumetric injection method based on crude oil and considering compressibility to obtain fluid parameters that more accurately reflect the underground reservoir properties. A permeability analysis module obtains an instability index, characterizing the stability of fluid viscosity in the local time domain. Fuzzy processing, combined with real-time deviations in differential pressure data, is then used to obtain a viscosity calibration confidence level, providing a double assessment of the confidence level of the measured viscosity and a reliable basis for obtaining corrected viscosity values. Finally, the viscosity calibration confidence level is used to obtain corrected viscosity values, improving the accuracy of permeability calculations. The permeability is finally obtained using a steady-state method or a pressure pulse decay method, providing further data support. This invention measures the compressibility of crude oil and core porosity under different temperature and pressure conditions, introduces fuzzy logic and differential pressure deviation, and dynamically corrects viscosity data, reducing the impact of fluid fluctuations and sensor errors, thereby improving the accuracy of permeability and providing more accurate data support for shale oil reservoir analysis. Attached Figure Description

[0048] To more clearly illustrate the technical solutions and advantages in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0049] Figure 1 This is a schematic diagram of an in-situ fluid parameter and physical property measurement device for shale oil reservoirs provided in an embodiment of the present invention.

[0050] Figure 2 This is a system block diagram of an in-situ fluid parameter and physical property measurement system for shale oil reservoirs provided in one embodiment of the present invention;

[0051] Figure 3 A curve showing the variation of crude oil compressibility coefficient is provided in one embodiment of the present invention;

[0052] Figure 4 A core porosity variation curve provided in one embodiment of the present invention;

[0053] Figure 5 This is a permeability variation curve provided in one embodiment of the present invention.

[0054] The following valves are labeled in the diagram: 1. Confining pressure pump; 2. First pressure sensor; 3. First control valve; 4. First constant speed and constant pressure pump; 5. Second control valve; 6. Third control valve; 7. Fourth control valve; 8. Fifth control valve; 9. Vacuum pump; 10. Second pressure sensor; 11. Liquid supply tank; 12. Third pressure sensor; 13. Sixth control valve; 14. Injection end reference chamber; 15. Seventh control valve; 16. Eighth control valve; 17. Core holder; 18. Ninth control valve; 19. Tenth control valve. 20. Eleventh control valve, 21. Twelfth control valve, 22. Thirteenth control valve, 23. Receiver reference chamber, 24. Fourteenth control valve, 25. Fourth pressure sensor, 26. Fifteenth control valve, 27. Second constant speed and constant pressure pump, 28. Overlying pressure control system, 29. Injection end pore fluid pressure system, 30. Receiver end pore fluid pressure system, 31. Core holder system, 32. Constant temperature system, 33. Vacuum system, 34. Liquid supply system, 35. Differential pressure sensor. Detailed Implementation

[0055] To further illustrate the technical means and effects adopted by the present invention to achieve its intended purpose, the following, in conjunction with the accompanying drawings and preferred embodiments, details the specific implementation, structure, features, and effects of a shale oil reservoir in-situ fluid parameter and physical property measurement device and method proposed according to the present invention. In the following description, different "one embodiment" or "another embodiment" do not necessarily refer to the same embodiment. Furthermore, specific features, structures, or characteristics in one or more embodiments can be combined in any suitable form.

[0056] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0057] The following description, in conjunction with the accompanying drawings, details the specific scheme of the in-situ fluid parameter and physical property measurement device and method for shale oil reservoirs provided by the present invention.

[0058] Please see Figure 1 The diagram illustrates a schematic of an in-situ fluid parameter and physical property measurement device for shale oil reservoirs according to an embodiment of the present invention. Figure 1 The diagram shows the connection relationships between the various devices;

[0059] The experimental setup includes an overlying pressure control system 28, an injection end pore fluid pressure system 29, a receiving end pore fluid pressure system 30, a constant temperature system 32, a core holder system 31, a vacuum system 33, and a liquid supply system 34.

[0060] The main function of the overburden pressure control system 28 is to apply the overburden pressure required for the experiment to the core holder. It includes a confining pressure pump 1 and a first pressure sensor 2. The confining pressure pump 1 is connected to the core holder system 31 through a pipeline. The pipeline is equipped with a first control valve 3 and a first pressure sensor 2.

[0061] The function of the pore fluid pressure system is to provide the fluid medium and pressure required for testing, including the injection-end pore fluid pressure system 29 and the receiving-end pore fluid pressure system 30. The injection-end pore fluid pressure system 29 mainly includes a first constant-speed constant-pressure pump 4 and a third pressure sensor 12; the receiving-end pore fluid pressure system 30 mainly includes a second constant-speed constant-pressure pump 27 and a fourth pressure sensor 25. The first constant-speed constant-pressure pump 4 and the second constant-speed constant-pressure pump 27 are connected to the core holder system 31, the vacuum system 33, and the liquid supply system 34 respectively through pipelines. The relevant pipelines are equipped with a second control valve 5, a third control valve 6, a third pressure sensor 12, a sixth control valve 13, an injection-end reference chamber 14, a seventh control valve 15, an eighth control valve 16, a tenth control valve 19, an eleventh control valve 20, a thirteenth control valve 22, a receiving-end reference chamber 23, a fourteenth control valve 24, a fourth pressure sensor 25, and a fifteenth control valve 26.

[0062] The main function of the core holder system 31 is to hold the core. The upper and lower ends of the core holder 17 are connected to the injection end pore fluid pressure system 29, the receiving end pore fluid pressure system 30 and the vacuum system 33 through pipelines, respectively. The relevant pipelines are equipped with a ninth control valve 18, a differential pressure sensor 35, an eleventh control valve 20 and a twelfth control valve 21.

[0063] The main function of the temperature control system 32 is to maintain a constant experimental temperature, including the heater and the temperature control chamber.

[0064] The main function of the vacuum system 33 is to extract air from the fluid pressure system, pipelines and core holder system to ensure accurate measurement results. It includes a vacuum pump 9 and a second pressure sensor 10. The vacuum pump 9 is connected to the injection end pore fluid pressure system 29, the receiving end pore fluid pressure system 30, the core holder system 31 and the liquid supply system 34 through pipelines. The pipelines are equipped with a fifth control valve 8 and a second pressure sensor 10.

[0065] The main function of the liquid supply system 34 is to store fluids such as crude oil and supply liquid to the first constant speed and constant pressure pump 4 and the second constant speed and constant pressure pump 27. The relevant pipelines are equipped with a fourth control valve 7 and a liquid supply tank 11.

[0066] It also includes an in-situ fluid parameter and physical property measurement system for shale oil reservoirs, used for parameter measurement by the control device.

[0067] Figure 1All systems mentioned are subsystems controlled by the shale oil reservoir in-situ fluid parameter and property measurement system; please refer to [link / reference]. Figure 2 The diagram shows a system block diagram of an in-situ fluid parameter and physical property measurement system for shale oil reservoirs provided in an embodiment of the present invention, including a control and acquisition module 101, a compression analysis module 102, a pore analysis module 103, and a permeability analysis module 104.

[0068] The control and acquisition module 101 is used to automatically control the device to conduct experiments and acquire experimental data based on a preset experimental program.

[0069] The main function of the control and acquisition module 101 is to execute the preset experimental program, control the instruments and valves through the computer to achieve automated control, drive the various subsystems to work together, and collect raw data such as temperature, pressure, and flow rate throughout the process; providing a data basis for the subsequent analysis module to calculate parameters such as porosity and permeability.

[0070] It should be noted that the preset experimental program is stored in the FPGA chip, and the preset experimental program can be adjusted according to actual needs, which will not be limited here; in another embodiment of the present invention, a user interface can also be provided by integrating hardware such as a touch screen and knobs to realize the rapid setting of experimental parameters and flexible control of the process.

[0071] Compression analysis module 102 is used to obtain the crude oil compression coefficient based on the experimental data of each experiment.

[0072] Currently, the measurement media for liquid-based methods of porosity and permeability are generally single reagents such as brine and white oil. Since shale reservoirs have different wettability to different fluids, crude oil produced from shale reservoirs is selected as the best saturated reagent in order to accurately match shale reservoirs.

[0073] Since fluids all have a certain degree of compressibility, the compressibility coefficient for a single medium can be obtained by consulting relevant data. However, because crude oil is a complex mixture, the compressibility coefficient cannot be directly looked up. It must be measured according to different pressures and temperatures. Therefore, the compressibility coefficient of crude oil is obtained based on the experimental data of each experiment to provide data support for the accurate analysis of porosity and permeability.

[0074] Preferably, in one embodiment of the present invention, the method for obtaining the crude oil compressibility coefficient includes:

[0075] Considering that the compressibility of a liquid is related to both temperature and pressure, a controlled variable approach is adopted here. The initial pore fluid pressure and the pressure change are fixed, and experiments are conducted at all preset temperatures one by one. In each experiment, the initial pore fluid pressure and the crude oil compressibility under the corresponding temperature conditions are obtained based on the liquid volume change before and after the pressure increase.

[0076] The experimental measurement process for the compressibility coefficient of crude oil is consistent for each test. Only one example will be described here, and will not be repeated. The initial pore fluid pressure is set at 60 MPa, the pressure variation is fixed at 10 MPa, and the preset temperature is 40℃. The specific process includes:

[0077] (a1) Close the eighth control valve 16 between the injection end pore fluid pressure system 29 and the core holder system 31, open the third control valve 6 between the injection end pore fluid pressure system 29 and the vacuum system 33, close the fourth control valve 7 of the liquid supply system 34, start the vacuum pump 9, and evacuate the injection end pore fluid pressure system 29 and related pipelines.

[0078] (a2) After the vacuuming is completed, close the third control valve 6 between the injection end pore fluid pressure system 29 and the vacuuming system 33;

[0079] (a3) Open the fourth control valve 7 of the liquid supply system 34, start the first constant speed and constant pressure pump 4, let it draw liquid, fill the pump body with crude oil, stop after it is full, and then close the fourth control valve 7 of the liquid supply system 34.

[0080] (a4) Turn on the constant temperature system 32 and set the required experimental temperature. It is 40℃;

[0081] (a5) Start the first constant speed and constant pressure pump 4 and set the (initial) pore fluid pressure. The pressure is 60 MPa. After the temperature and pressure reach equilibrium, the volume of liquid inside the first constant-speed constant-pressure pump 4 is recorded. The volume was 99.9963 ml.

[0082] (a6) Increase the pore fluid pressure to , The pressure is 70 MPa. After the temperature and pressure reach equilibrium, the volume of liquid inside the first constant-speed constant-pressure pump 4 is recorded. The volume was 99.4812 ml.

[0083] (a7) The calculated pressure is ,temperature Compressibility of the fluid under the given conditions:

[0084] As an example, in each experiment, the change in liquid volume before and after the pressure increase is taken as the numerator, the product of the pressure change and the initial total volume of the liquid is taken as the denominator, and the ratio of the fractions is taken as the corresponding crude oil compressibility coefficient.

[0085] The calculation formula includes:

[0086] ;

[0087] In the formula, The compressibility coefficient of a fluid represents the relative rate of change of fluid volume under a unit pressure change, with units of 1 / MPa. The volume of liquid inside the first constant-speed, constant-pressure pump 4 under initial pore fluid pressure and temperature conditions. The volume of liquid in the first constant-speed, constant-pressure pump 4 under increased pore fluid pressure and temperature conditions is expressed in ml. This refers to the volume of the pipeline section, in ml. The initial pore fluid pressure, The pressure is the increased pore fluid pressure, expressed in MPa.

[0088] Calculation Principle: This formula is based on the fundamental definition of compressibility in fluid mechanics, which is the relative change in fluid volume caused by a unit change in pressure under isothermal conditions. In the experiment, the pressure of a closed fluid system is actively changed, and the reduction in liquid volume within the system during this process is precisely measured. This is also the change in liquid volume before and after the pressure increase, and then the change in volume is divided by the initial total volume of the system. With pressure change The product of these factors is used to calculate the compressibility coefficient, which accurately reflects the compressibility of a fluid at a specific temperature and initial pressure. The core of this principle lies in quantifying the microscopic compressibility of a fluid through measurable macroscopic volume and pressure changes.

[0089] Substituting the data into the formula, the compressibility coefficient of crude oil under the conditions of 40℃ temperature and 60MPa pressure was calculated. =0.0005054 / MPa.

[0090] By changing the temperature and repeating the experiment, the compressibility coefficient of crude oil was calculated at 50℃, 60℃, 70℃, 80℃, 90℃, and 100℃. The calculated compressibility coefficients were 0.0005066 / MPa, 0.0005071 / MPa, 0.0005079 / MPa, 0.0005083 / MPa, 0.0005089 / MPa, and 0.0005091 / MPa, respectively. Please refer to [link / reference needed]. Figure 3 The diagram illustrates a curve showing the variation of the crude oil compressibility coefficient according to an embodiment of the present invention. Figure 3 The horizontal axis represents temperature, and the vertical axis represents the compressibility coefficient.

[0091] By changing the initial pore fluid pressure and repeating the experimental process, the compressibility coefficient of crude oil under different temperature and pressure conditions can be obtained.

[0092] In other embodiments of the present invention, the implementer may design the measurement experiment of crude oil compressibility according to actual needs, such as changing the step size of temperature or pressure, etc. Each experiment can be repeated multiple times and the average is taken to reduce the single error, which will not be elaborated further.

[0093] The porosity analysis module 103 is used to measure the core porosity using the compressibility coefficient method based on experimental data and the crude oil compressibility coefficient.

[0094] The compressibility coefficient of a fluid under certain temperature and pressure conditions is a fixed value. Therefore, the compressibility coefficient method can be used to calculate the pore volume of the core. However, this method requires prior measurement of the fluid's compressibility coefficient. Thus, in porosity analysis experiments, the compressibility coefficient of crude oil is retrieved and the experimental data is analyzed. The compressibility coefficient method is then used to measure the core porosity, eliminating the cumbersome pipeline cleaning process and simplifying the experimental procedure. By using formation crude oil and simulating formation temperature and pressure conditions, "in-situ porosity" that more accurately reflects the physical properties of underground reservoirs is obtained, providing a more reliable key parameter for accurate assessment of shale oil reserves and formulation of development plans.

[0095] Preferably, in one embodiment of the present invention, a cylindrical shale sample is prepared using wire cutting technology. The cylindrical sample has a diameter of 2.50 cm and a length of 2.50 cm. The prepared shale sample is cleaned with dichloromethane as a cleaning solvent for at least 72 hours, and the fluorescence detection level of the shale sample after cleaning is less than level 3. After oil removal, the sample is dried under vacuum at 60°C for 8 hours. The shale sample is then transferred to a desiccator for storage, ready for subsequent experimental analysis.

[0096] The experimental measurement process for core porosity was consistent for each test; only one example will be described here, and will not be repeated. The specific process includes:

[0097] (b1) Determine the overlying pressure required for the experiment based on the geological information of the measured sample. For 80MPa and test temperature The temperature is set at 100℃ (the implementer may adjust this according to the actual situation); the initial pore fluid pressure is set at 60MPa, and the pressure change is set at 10MPa.

[0098] (b2) Load the core into the core holder 17 and set the overburden pressure. Set the pressure to 80 MPa; turn on the temperature control system 32 and set the required experimental temperature. 100℃;

[0099] (b3) If experimental data on the compressibility coefficient of crude oil under corresponding high temperature and high pressure conditions already exist, the crude oil compressibility coefficient under corresponding high temperature and high pressure conditions can be directly called; otherwise, the compression analysis module 102 can be called to conduct experiments and obtain the crude oil compressibility coefficient.

[0100] (b4) Open the eighth control valve 16 between the injection end pore fluid pressure system 29 and the core holder system 31, and set the pore fluid pressure to [value missing]. The pressure is 60 MPa, and fluid is injected into the core.

[0101] (b5) After the pressure and temperature stabilize, record the liquid volume of the first constant speed and constant pressure pump 4 at this time. It is 97.3706 ml;

[0102] (b6) Increase the fluid pressure to 70MPa. After the temperature and pressure reach equilibrium, record the volume of liquid inside the first constant-speed constant-pressure pump 4 at this point. It is 96.8441 ml;

[0103] Using the same method as the compression analysis module 102, the pressure can be obtained as follows: The formulas for calculating the compressibility coefficient of crude oil under temperature T include:

[0104] ;

[0105] In the formula: The compressibility coefficient of the fluid is expressed in units of 1 / MPa. The initial pore fluid pressure, The pressure of the pore fluid after the increase is expressed in MPa. for The volume of liquid inside the first constant-speed, constant-pressure pump 4 under the given conditions. for The volume of liquid inside the first constant-speed, constant-pressure pump 4 under the given conditions, in ml. For the pore volume of the injection end pipeline, The pore volume of the receiving pipeline. This represents the pore volume of the core sample, in ml.

[0106] This formula is used to calculate the compressibility of a fluid under specific temperature and pressure conditions. Pressure is measured experimentally from... Rise to At that time, the fluid volume inside the first constant speed and constant pressure pump 4 increased from... Reduce to The compressibility coefficient of the fluid is calculated by combining the total fluid volume of the system (including the volume inside the pump, the volume of the pipeline, and the volume of the core pores); the formula assumes that the fluid is uniform and has linear compressibility behavior within the pressure variation range.

[0107] Considering that the compressibility coefficient of crude oil is known in each porosity analysis experiment, the equivalent volume of the total fluid (crude oil) in the system can be obtained by combining the change in liquid volume and pressure before and after the pressure increase with the corresponding compressibility coefficient of crude oil. Then, based on the difference between the equivalent volume and the total liquid volume of the pump and pipeline, the pore volume of the core sample can be deduced. Finally, combined with the core sample volume, the core porosity of the core sample can be obtained.

[0108] As an example, the change in liquid volume before and after the pressure increase is taken as the numerator, the product of the pressure change and the corresponding crude oil compressibility coefficient is taken as the denominator, and the ratio of the fractions is taken as the equivalent volume of the corresponding experiment.

[0109] That is to The calculation formula is modified as follows: ,So ;

[0110] Core porosity at this time , ;

[0111] In the formula, Core porosity represents the proportion of pore volume to total volume in a core sample; it is dimensionless. This represents the total volume of the core sample, in ml.

[0112] The formula is based on the principle of fluid compressibility, calculating core porosity by measuring the change in fluid volume under varying pressure. Rise to At that time, the amount of decrease (change) in fluid volume. Compressibility of fluid And pressure difference (pressure change) This part reflects the compressibility effect of the fluid throughout the entire system (including pumps, pipelines, and core pores). The formula... The equivalent volume representing the change in fluid volume under pressure variation, minus the volume of the pump and pipeline. Then, the pore volume of the core was obtained, and finally divided by the core sample volume. That is, the porosity was obtained. .

[0113] Substituting the data into the formula, the porosity of the core sample was calculated to be 8.99% under the conditions of 100℃ temperature and 60MPa pressure.

[0114] By varying the initial pore fluid pressure while keeping the pressure change constant, compression analysis experiments were repeated. The core porosity was calculated under initial pore fluid pressures of 50 MPa, 40 MPa, 30 MPa, 20 MPa, and 10 MPa. The calculated core porosities were 8.54%, 8.01%, 7.63%, 7.31%, and 7.02%, respectively.

[0115] Please see Figure 4 The figure shows a core porosity variation curve provided by an embodiment of the present invention, wherein the horizontal axis is the pore fluid pressure, corresponding to the initial pore fluid pressure set in the experiment, and the vertical axis is the porosity, corresponding to the core porosity.

[0116] It should be noted that the method for calculating the volume of core samples is a well-known technique, and practitioners can design their own pore analysis experiments as needed, so it will not be elaborated further.

[0117] The permeability analysis module 104 is used to extract viscosity and pressure difference data from the experimental data; analyze the fluctuation stability of viscosity data within a preset historical neighborhood of each viscosity data point to obtain the instability index of each viscosity data point; process the instability index based on fuzzy logic and combine it with the deviation of the pressure difference data at the same moment to obtain the viscosity calibration confidence level; fuse the viscosity data at each moment with the previous moment based on the viscosity calibration confidence level to obtain the corrected viscosity value; and measure the permeability using the steady-state method based on the corrected viscosity value and the experimental data.

[0118] In one embodiment of the present invention, the permeability under high temperature and high pressure conditions is measured using the steady-state method. Considering that in in-situ viscosity measurements of shale oil reservoirs, the heterogeneity of the reservoir itself and the effects of energy storage stress and fluid phase separation caused by nanoscale pores can lead to measurement islands (i.e., the measured data points are scattered and not typical) and static assumptions (i.e., the dynamic flow of fluid with time as the spatial element is in a static state), the measured results cannot fully reflect the true flow state of the formation fluid, which may mislead development design and overestimate or underestimate the recovery rate. Therefore, it is necessary to correct the viscosity data first.

[0119] In one embodiment of the present invention, the process of correcting the viscosity data is consistent each time. Only one example is described here, and will not be repeated. The permeation analysis experiment design is as follows:

[0120] (d1) Based on the geological information of the measured samples, determine the overlying pressure required for the experiment. Pore ​​fluid pressure and test temperature As an example, overlying pressure 80 MPa, pore fluid pressure For 60MPa and test temperature 100℃;

[0121] (d2) Based on pore fluid pressure and test temperature The viscosity of crude oil under these temperature and pressure conditions was measured using a high-temperature, high-pressure viscometer. ;

[0122] (d3) Measure the diameter L and length D of the sample, load the core into the core holder, and set the overburden pressure. As an example, the cylindrical sample has a diameter of 2.50 cm and a length of 2.50 cm.

[0123] (d4) Open the eighth control valve 16 between the injection end pore fluid pressure system 29 and the core holder system 31, open the tenth control valve 19 between the receiving end pore fluid pressure system 30 and the core holder system 31, open the fifth control valve 8 between the injection end pore fluid pressure system 29 and the vacuum system 33, close the fourth control valve 7 of the liquid supply system 34, start the vacuum pump 9, and evacuate the injection end pore fluid pressure system 29, the receiving end pore fluid pressure system 30, the core holder system 31 and the pipeline;

[0124] (d5) After the vacuuming is completed, close the fifth control valve 8 of the vacuuming system 33;

[0125] (d6) Open the fourth control valve 7 of the liquid supply system 34, start the first constant speed and constant pressure pump 4 at the injection end and the second constant speed and constant pressure pump 27 at the receiving end to draw liquid, fill the pump body with crude oil, stop after it is full, and close the fourth control valve 7.

[0126] (d7) Turn on the constant temperature system 32 and set the required experimental temperature. ;

[0127] (d8) Start the first constant speed and constant pressure pump 4, and set the injection end pore fluid pressure to [value missing]. Set the pore fluid pressure at the receiving end to be , Establish a pressure difference of 50 MPa before and after the core sample, wait for the inflow and outflow rates to stabilize, and record the viscosity and pressure difference data.

[0128] The acquisition frequency for both viscosity and differential pressure data was set to 10Hz, and the data were acquired synchronously. Each type of data was then Z-score standardized to eliminate the influence of dimensions.

[0129] Considering that shale oil reservoir fluids are subjected to shear forces when passing through nanoscale pore channels, are adsorbed by the surface of rock minerals, and are subject to microscopic fluctuations in the temperature field, the effective viscosity is not a constant value, but changes continuously with time and different flow states.

[0130] The stability of viscosity data fluctuations reflects changes in fluid flow state. Therefore, analyzing the stability of viscosity data fluctuations within a preset historical neighborhood of each viscosity data point and obtaining the instability index of each viscosity data point characterizes the stability of fluid viscosity in the local time domain, providing a basis for subsequently obtaining viscosity calibration confidence and adjusting viscosity values.

[0131] The analysis process is the same for each viscosity data point; only one example will be described here.

[0132] Preferably, in one embodiment of the present invention, the length of the preset historical neighborhood is 51, containing 51 data points; considering that the fluctuation trend or pattern of viscosity data changes over time, in order to more accurately capture local fluctuation features, for each viscosity data, the viscosity data sequence within the preset historical neighborhood is used to obtain change points using the CUSUM change point detection algorithm, and the viscosity data sequence is divided into subsequences based on the change points.

[0133] The significance threshold was set to three standard deviations to effectively distinguish between real property changes and random noise. The sequence was divided using change points, which corresponded to the endpoints of the preceding subsequence. For example, in 1-51, change points 18 and 35 were divided into 1-18, 19-35, and 36-51. These change points represent critical moments when the fluid flow state undergoes significant changes, indicating macroscopic trend reversals in viscosity caused by pore size effects, instantaneous changes in fluid composition, or system disturbances. Complex non-stationary sequences were further decomposed into multiple relatively stationary sub-intervals for subsequent analysis.

[0134] Considering that the fluctuation stability of data within a subsequence directly reflects the smoothness of flow characteristics within the corresponding time period, and the number of change points reflects the frequency of significant changes in fluid flow state, the instability index of the corresponding viscosity data is obtained based on the fluctuation stability of viscosity within all subsequences and the number of change points.

[0135] As an example, considering that the coefficient of variation is a coefficient that represents the fluctuation of data, the larger the coefficient of variation, the worse the fluctuation stability, we calculate the coefficient of variation of each subsequence separately, and multiply the average value of the coefficient of variation by the total number of change points as the instability index A of the corresponding viscosity data.

[0136] The greater the total number of variable points, the more times the fluid undergoes macroscopic viscosity trend reversals due to pore size effects, instantaneous changes in fluid composition, or system disturbances as it flows through micro- and nano-sized pores. This indicates poorer fluctuation stability and a larger instability index. The average value of the coefficient of variation reflects the stability of the fluid's viscosity in each relatively stable phase. A smaller value indicates greater stability and a smaller instability index.

[0137] When fluid flows through the micro- and nano-pores of shale, it is affected by the coupling effects of multiple dynamic factors, such as shear effect, adsorption of fluid by rock surface, and temperature field fluctuations on the micro- and nano-scale surface and within the pores of rock. Therefore, the true viscosity of the fluid will exhibit nonlinear and unsteady changes in a short period of time, showing a certain degree of endogenous instability. At the same time, the actual working conditions of the device are not taken into account for the impact on the measurement, and the viscosity instability index obtained by time-varying point discrimination and segmented stability analysis cannot fully reflect the reliability of each real-time measured viscosity value.

[0138] Considering that fuzzy logic is often used to handle qualitative concepts with ambiguous boundaries and does not rely on precise mathematical models, and that the deviation of differential pressure data reflects the degree to which the sensor deviates from its ideal calibrated working state, the instability index is processed based on fuzzy logic. Combined with the deviation of differential pressure data at the same moment, the viscosity calibration confidence is obtained. The confidence of the measured viscosity is evaluated twice, providing a reliable basis for obtaining the corrected viscosity value in the future, and ultimately improving the accuracy of permeability.

[0139] Preferably, in one embodiment of the present invention, all instability indices before each time point are arranged in ascending order of time to obtain the viscosity instability sequence at each time point (including the instability index of each time point itself), and the viscosity instability sequence at each acquisition time point is used as input to evaluate the preliminary confidence level of the instability index using fuzzy logic.

[0140] Three fuzzy sets—low, medium, and high—are set up, and a triangular membership function is used. Specifically, the input is fuzzified using the preset membership function, converting it into membership degrees on three fuzzy linguistic variables: "low," "medium," and "high." Then, the fuzzy inference stage begins, where calculations are performed according to pre-defined fuzzy rules to obtain the initial confidence fuzzy set of the output. Finally, the centroid method is used for defuzzification, transforming the output fuzzy confidence set into a precise value between 0 and 1, i.e., the initial confidence C, thus completing the nonlinear mapping from viscosity fluctuation characteristics to a single confidence evaluation value.

[0141] Among them, for the preset membership function, the low fuzzy set is preset to [0,0,0.3], the medium fuzzy set is preset to [0.2,0.5,0.8], and the high fuzzy set is preset to [0.7,1,1]. In other embodiments of the present invention, it can be adjusted based on expert experience.

[0142] Meanwhile, considering that the pressure difference driving the fluid through the sensor is not equal to the pressure difference at calibration, which will also introduce systematic error, the difference between the pressure difference data at each moment and the preset pressure difference value is mapped by a preset attenuation function as the attenuation factor.

[0143] As an example, the preset decay function is: , As the attenuation factor, This is the absolute value of the difference between the differential pressure data at the analyzed time and the preset differential pressure value, corresponding to the difference between the differential pressure data and the preset differential pressure value, reflecting the deviation of the differential pressure data. The attenuation coefficient is... ; It is an exponential function with the natural constant e as the base; the confidence level decreases slowly when the pressure difference is slightly deviated, and decays rapidly when the pressure difference is large; this can improve sensitivity and maintain good stability.

[0144] Finally, the initial confidence level and attenuation factor corresponding to the viscosity data at each time point are combined to obtain the viscosity calibration confidence level.

[0145] As an example, the product of the initial confidence level and the attenuation factor corresponding to the viscosity data at each time step is used as the viscosity calibration confidence level at each time step.

[0146] In the calculation of viscosity calibration confidence B, C expresses the instability of the measurement environment implied by the unsteady characteristics of the fluid's own viscosity fluctuations. Combined with F, which expresses the risk of systematic error introduced by the sensor due to the deviation of the working pressure difference from the ideal calibration conditions, the viscosity calibration confidence B is comprehensively reflected. The larger the value of B, the more stable the measurement environment and the more ideal the sensor's working conditions, and the higher the reliability of its measurement results.

[0147] It should be noted that fuzzy logic is a well-known technology, and implementers can adjust the attenuation factor to adjust the sensitivity of pressure difference deviation; they can also use a weighted summation method to fuse C and F; or they can arrange the previously preset number of adjacent instability indices at each time point in ascending order of time, such as 50, or take all if there are fewer, to obtain the viscosity instability sequence at each time point (including the instability index of each time point itself), which will not be elaborated further.

[0148] Considering that viscosity values ​​at a single moment may be affected by instantaneous disturbances, and that viscosity calibration confidence reflects the reliability of measurement results, viscosity data at each moment are fused with the previous moment based on viscosity calibration confidence. This incorporates historical information from the previous moment to obtain corrected viscosity values, thereby transforming from static, isolated measurements to dynamic, context-aware intelligent estimation and improving the stability and robustness of permeability calculation results.

[0149] Preferably, in one embodiment of the present invention, considering that the higher the viscosity calibration confidence level B is, the more stable the measurement environment is at the corresponding moment, the better the sensor works, and the more reliable the measurement data is, the higher the weight is given to the measurement value at the same moment, so as to be able to quickly respond to the actual changes in fluid viscosity; when B is lower, it indicates that the measurement value at the same moment is less reliable, so the previous moment is given a greater weight, and the estimation value depends on the relatively stable estimate value at the previous moment.

[0150] Therefore, the viscosity data at the same time are weighted by the viscosity calibration confidence level at each time step, and the viscosity data at the previous time step is weighted by the difference between constant 1 and viscosity calibration confidence level. The weighted sum is used as the corrected viscosity value at each time step.

[0151] After obtaining data supporting the corrected viscosity value, the permeability under high temperature and high pressure conditions was finally measured using the steady-state method based on the corrected viscosity value and experimental data.

[0152] In a preferred embodiment of the present invention, in each experiment, the corrected viscosity value, core length, liquid flow rate, core cross-sectional area, and pressure difference between the core injection end and the receiving end are processed based on the steady-state method of Darcy's law at the current moment to obtain the permeability under the high temperature and high pressure conditions of the corresponding experiment.

[0153] As an example, taking any single experiment as an example, the formula for calculating permeability includes:

[0154] ;

[0155] In the formula, Permeability is the ability of a rock core to allow fluid to pass through it, and is measured in millidarcy mD. This is the corrected viscosity value at the current acquisition time, in Pascals per second. The core length represents the length of the fluid flow path within the core, measured in meters (m). Flow rate, representing the volume of fluid passing through the core per unit time, is expressed in units of 1000 liters. , The cross-sectional area of ​​the rock core represents the cross-sectional area of ​​the fluid flow, with units of 1000 m². , The pressure difference represents the pressure difference between the core injection end and the receiving end, and the unit is MPa.

[0156] The calculation formula is based on Darcy's law, a steady-state method for measuring permeability. The principle is that under steady-state flow conditions (i.e., stable flow rate and pressure difference), the flow rate Q of a fluid passing through a porous medium (such as a rock core) is related to the pressure difference. and core cross-sectional area Proportional to fluid viscosity It is inversely proportional to the core length L. Permeability K, as a proportionality constant, reflects the degree to which the core itself hinders fluid flow; the larger the value, the easier it is for fluid to pass through the core.

[0157] The formula calculates the permeability of the core under specific temperature and pressure conditions by directly measuring these parameters, thereby assessing the fluid flow characteristics of the reservoir and more realistically reflecting the complex flow state of formation fluids. This provides more accurate data support for shale oil reservoir evaluation and development plan formulation.

[0158] One embodiment of the present invention also provides a method for measuring in-situ fluid parameters and physical properties of shale oil reservoirs, the method comprising: conducting experiments and collecting experimental data based on an automatic control device with a preset experimental program;

[0159] The crude oil compressibility coefficient is obtained based on the experimental data from each experiment;

[0160] Based on experimental data and crude oil compressibility coefficient, core porosity was measured using the compressibility coefficient method.

[0161] Viscosity and pressure difference data are extracted from the experimental data; the stability of viscosity data fluctuations is analyzed within a preset historical neighborhood for each viscosity data point to obtain the instability index for each viscosity data point; the instability index is processed based on fuzzy logic, and combined with the deviation of the pressure difference data at the same moment to obtain the viscosity calibration confidence level; the viscosity data at each moment is fused with the previous moment based on the viscosity calibration confidence level to obtain the corrected viscosity value; the permeability is measured using the steady-state method based on the corrected viscosity value and the experimental data.

[0162] The implementation process of a method for measuring in-situ fluid parameters and properties in shale oil reservoirs has been described in a system for measuring in-situ fluid parameters and properties in shale oil reservoirs, and will not be repeated here.

[0163] One embodiment of the present invention also provides a method for measuring core porosity based on the volumetric injection method. The method is based on crude oil and takes compressibility into account. Specifically, it includes: after preparing the sample, conducting an experiment and collecting experimental data based on an automatic control device according to a preset experimental program, and then measuring the core porosity based on the volumetric injection method. The experimental measurement process for each core porosity measurement based on the volumetric injection method is consistent; only one example is described here, and will not be repeated. The specific steps are as follows:

[0164] (c1) Determine the overlying pressure required for the experiment based on the geological information of the measured sample. 80 MPa, pore fluid pressure For 60MPa and test temperature 100℃;

[0165] (c2) Load the core into the core holder 17 and set the overburden pressure. It is 80 MPa;

[0166] (c3) Open the eighth control valve 16 between the injection end pore fluid pressure system 29 and the core holder system 31, close the tenth control valve 19 between the receiving end pore fluid pressure system 30 and the core holder system 31, open the third control valve 6 between the injection end pore fluid pressure system 29 and the vacuum system 33, close the fourth control valve 7 of the liquid supply system 34, start the vacuum pump 9, and evacuate the injection end pore fluid pressure system 29, the core holder system 31 and the pipeline;

[0167] (c4) After the vacuuming is completed, close the eighth control valve 16 between the core holder system 31 and the injection end pore fluid pressure system 29;

[0168] (c5) Close the fifth control valve 8 of the vacuum system 33, open the fourth control valve 7 of the liquid supply system 34, start the first constant speed and constant pressure pump 4 to draw liquid, fill the pump body with crude oil, stop after it is full, and close the third control valve 6 between the liquid supply system 34 and the injection end pore fluid pressure system 29.

[0169] (c6) Turn on the constant temperature system 32 and set the required experimental temperature. 100℃;

[0170] (c7) Start the first constant speed and constant pressure pump 4 and set the pore fluid pressure. The pressure is 60 MPa. After the temperature and pressure reach equilibrium, the volume of liquid inside the first constant-speed constant-pressure pump 4 is recorded. It is 99.9963ml;

[0171] (c8) Open the eighth control valve 16 between the injection end pore fluid pressure system 29 and the core holder system 31. After the temperature and pressure reach equilibrium, record the volume of liquid in the first constant speed and constant pressure pump 4 at this time. ;

[0172] (c9) Calculate the volume of crude oil injected into the core:

[0173] ;

[0174] Dimensional analysis: This refers to the pore volume of a rock core, that is, the total volume of all pore spaces inside the core, expressed in ml. This represents the volume of liquid inside the first constant-speed, constant-pressure pump 4 in the initial state. This indicates the volume of liquid inside the first constant-speed, constant-pressure pump 4 in the final state, in ml. The volume of the injection end pipeline (the volume of the pipeline between the first constant speed and constant pressure pump 4 and the core holder 17) is expressed in ml.

[0175] Calculation principle: This formula is based on the principle of volume conservation: the initial volume of liquid in the first constant-speed and constant-pressure pump 4. Reduced to [amount] after fluid injection. Reduced volume This is equal to the total volume injected into the system, which includes the volume of the filling pipeline. and the volume entering the core pores Therefore, the pore volume of the core can be obtained by subtracting the known pipeline volume from the reduced total volume. This reflects the pore characteristics of the core under high temperature and high pressure conditions.

[0176] (c10) Calculate porosity. The formula for calculating core porosity includes:

[0177] ;

[0178] In the formula, Core porosity represents the proportion of pore volume to total volume in a core sample and is dimensionless. This represents the pore volume of the rock core. This indicates the total volume of the core sample, expressed in ml.

[0179] This formula is based on the volumetric injection method for calculating core porosity. Its principle is to consider compressibility by injecting a fluid (such as crude oil) into a pre-vacuumed core sample, allowing the fluid to completely fill the pore spaces, and then measuring the volume of the injected fluid (i.e., the pore volume). ), and compared with the total volume of the sample. In contrast, the pore volume ratio is obtained to quantify the rock's storage capacity. This method assumes that fluid can fully enter all connected pores and eliminates errors such as pipeline volume, thus accurately reflecting the pore characteristics of the rock under in-situ conditions.

[0180] One embodiment of the present invention also provides a method for measuring permeability based on the pressure pulse attenuation method, specifically including:

[0181] Experiments are conducted and experimental data is collected using an automatic control device based on a preset experimental procedure;

[0182] Viscosity and pressure difference data are extracted from the experimental data; the stability of viscosity fluctuations is analyzed within a preset historical neighborhood for each viscosity data point to obtain the instability index for each viscosity data point; the instability index is processed based on fuzzy logic, and combined with the deviation of the pressure difference data at the same moment to obtain the viscosity calibration confidence level; the viscosity data at each moment is fused with the previous moment based on the viscosity calibration confidence level to obtain the corrected viscosity value; the permeability is measured using the pressure pulse decay method based on the corrected viscosity value and the experimental data.

[0183] The procedures prior to permeability measurement have been described in a shale oil reservoir in-situ fluid parameter and physical property measurement system and will not be repeated here; the experimental data may also include the crude oil compressibility coefficient.

[0184] It should be noted that the experimental measurement process for measuring core porosity based on the volumetric injection method is the same each time. Only one example is described here, and it will not be repeated.

[0185] The specific process of measuring permeability using the pressure pulse decay method based on corrected viscosity values ​​and experimental data includes:

[0186] (e1) Based on the geological information of the measured sample, determine the overlying pressure required for the experiment. Pore ​​fluid pressure and test temperature As an example, overlying pressure 80 MPa, pore fluid pressure For 55MPa and test temperature 100℃;

[0187] (e2) Based on pore fluid pressure and test temperature The viscosity of crude oil under these temperature and pressure conditions was measured using a high-temperature, high-pressure viscometer. The corrected viscosity value is obtained, and the process of obtaining the corrected viscosity value will not be described again.

[0188] (e3) Obtain pressure as ,temperature The compressibility coefficient of the fluid (crude oil in this example) under the same conditions is the same as in step (b3).

[0189] (e4) Measure the diameter L and length D of the sample. As an example, the cylindrical sample has a diameter of 2.50 cm and a length of 2.50 cm. Place the core into the core holder 17 and set the overburden pressure to [value missing]. ;

[0190] (e5) Open the eighth control valve 16 between the injection end pore fluid pressure system 29 and the core holder system 31, open the ninth control valve 18 between the receiving end pore fluid pressure system 30 and the core holder system 31, open the fifth control valve 8 between the injection end pore fluid pressure system 29 and the vacuum system 33, close the fourth control valve 7 of the liquid supply system 34, start the vacuum pump 9, and evacuate the injection end pore fluid pressure system 29, the receiving end pore fluid pressure system 30, the core holder system 31 and the pipeline;

[0191] (e6) After the vacuuming is completed, close the fifth control valve 8 between the injection end pore fluid pressure system 29 and the vacuuming system 33;

[0192] (e7) Open the fourth control valve 7 of the liquid supply system 34, start the first constant speed and constant pressure pump 4 at the injection end and the second constant speed and constant pressure pump 27 at the receiving end to draw liquid, fill the pump body with crude oil, stop after it is full, and close the fourth control valve 7.

[0193] (e8) Turn on the constant temperature system 32 and set the required experimental temperature. ;

[0194] (e9) Start the first constant speed and constant pressure pump 4, and set the injection end pore fluid pressure to [value missing]. Start the second constant speed and constant pressure pump 27 at the receiving end, and set the pore fluid pressure at the receiving end to be [value missing]. Once the core is fully saturated, the pressure and temperature will reach a constant level.

[0195] (e10) Increase the pore fluid pressure at the injection end Then, the first constant-speed and constant-pressure pump 4 and the second constant-speed and constant-pressure pump 27 at the receiving end are turned off to establish the pressure difference between the upstream and downstream ends of the core sample, and the pressure value of the differential pressure sensor is recorded. With the changes over time;

[0196] ;

[0197] In the formula, Real-time pressure difference, representing the instantaneous pressure difference between the upstream and downstream of the core sample, in MPa. The initial pressure difference represents the initial pressure difference when the pressure pulse is applied, and its unit is MPa. is the pressure decay constant, representing the rate of pressure differential decay. Specifically, it is the reciprocal of the unit second, with the unit being 1 / s. t is the time elapsed since the pressure pulse was applied, with the unit being s.

[0198] Calculation principle: An initial pressure difference is applied to both ends of the core sample. Subsequently, due to the compressibility of the fluid (crude oil), the pressure difference will decrease exponentially over time. ), attenuation constant It reflects the flow rate of fluid through the pores of the rock core.

[0199] The formula for calculating (e11) permeability is:

[0200] ;

[0201] In the formula, Permeability is the ability of a rock core to allow fluid to pass through it, and is measured in millidarcy mD. This is the improved viscosity value at the current acquisition time, in Pascals per second. The core length represents the length of the fluid flow path within the core, measured in meters (m). The cross-sectional area of ​​the rock core represents the cross-sectional area of ​​the fluid flow, with units of 1000 m². , This is the pressure decay constant, specifically taken as the reciprocal of the unit of seconds, with units of 1 / s. The compressibility coefficient of a fluid represents the relative rate of change of fluid volume under a unit change in pressure. For the volume of the injection end reference chamber 14, The volume of the receiving reference chamber 23 is in ml.

[0202] Calculation principle: Permeability The fluid's viscosity and compressibility were taken into account. Core geometry (length) Cross-sectional area ) and reference chamber volume ( and The effect of differential pressure attenuation on the formula is expressed by the attenuation constant. By combining fluid and core parameters, the permeability of the core under in-situ high temperature and high pressure conditions was quantified, thus enabling a more accurate evaluation of the flow characteristics of shale oil reservoirs.

[0203] Substituting the data into the formula, the permeability of the core under the conditions of an overburden pressure of 80 MPa, an injection end pore fluid pressure of 55 MPa, and a test temperature of 100℃ is 0.00005486 mD.

[0204] Changing the pore fluid pressure at different injection ends Keeping the pressure difference constant, the permeability experiment was repeated, and the core permeability was calculated under the conditions of pore fluid pressure at the injection end of 50MPa, 45MPa, 40MPa, 35MPa, 30MPa, 25MPa, 20MPa, and 10MPa. The calculated core permeability was 0.00005123mD, 0.00004857mD, 0.00004231mD, 0.00003995mD, 0.00003421mD, 0.00003028mD, 0.00002854mD, and 0.00002433mD, respectively.

[0205] Please see Figure 5 It shows a permeability variation curve provided by an embodiment of the present invention, where the horizontal axis represents the pore fluid pressure at the injection end, corresponding to the settings in the experiment. The vertical axis corresponds to the permeability.

[0206] The testing device can accurately measure the fluid compressibility, porosity, and permeability under conditions of overburden pressure of 100 MPa, pore fluid pressure of 70 MPa, and temperature of 150℃; the lower limit for permeability measurement can reach... mD;

[0207] High-precision constant-speed and constant-pressure pumps are employed for both the overlying pressure control system 28 and the pore fluid pressure system (including two sets: one for the injection end and one for the receiving end). The flow rate range is 0.0001–30 ml / min, with a maximum pressure of 100 MPa, a volumetric metering accuracy of 0.1 μL, and a pressure control accuracy of 0.001 MPa. The system is equipped with a 10.2-inch LCD screen that displays pressure, flow rate, and their variation curves in real time, and supports computer connection and software control. It features multiple operating modes, including constant pressure, constant flow, and tracking, and integrates overpressure / underpressure protection and automatic compression compensation functions to ensure stable flow rate and safe and reliable system operation under high pressure.

[0208] In summary, to address the limitation of existing measurement technologies in accurately acquiring key fluid parameters under realistically simulated formation temperature and pressure conditions using formation crude oil as the medium, thus hindering the precise evaluation of shale oil reservoirs, this invention provides an in-situ fluid parameter and property measurement device and method for shale oil reservoirs. This invention utilizes an automatic control device with a control and acquisition module of an in-situ fluid parameter and property measurement system for shale oil reservoirs to conduct experiments and collect experimental data. Further, a compression analysis module obtains the crude oil compressibility coefficient for each experiment; a porosity analysis module measures core porosity using the compressibility coefficient method or volumetric injection method; a permeability analysis module analyzes the historical local stability of each viscosity to obtain an instability index; fuzzy processing and real-time deviation of differential pressure data are used to obtain a viscosity calibration confidence level; the viscosity calibration confidence level is then used to obtain a corrected viscosity value; and permeability is obtained using a steady-state method or pressure pulse decay method. This invention measures the compressibility of crude oil and core porosity under different temperature and pressure conditions, introduces fuzzy logic and differential pressure deviation, and dynamically corrects viscosity data, reducing the impact of fluid fluctuations and sensor errors, thereby improving the accuracy of permeability and providing more accurate data support for shale oil reservoir analysis.

[0209] It should be noted that the order of the above embodiments of the present invention is merely for descriptive purposes and does not represent the superiority or inferiority of the embodiments. The processes depicted in the accompanying drawings do not necessarily require a specific or sequential order to achieve the desired result. In some embodiments, multitasking and parallel processing are also possible or may be advantageous.

[0210] The various embodiments in this specification are described in a progressive manner. The same or similar parts between the various embodiments can be referred to each other. Each embodiment focuses on describing the differences from other embodiments.

Claims

1. A device for in-situ fluid parameter and physical property measurements of a shale oil reservoir, comprising a device body, characterized in that, It also includes an in-situ fluid parameter and physical property measurement system for shale oil reservoirs, used for parameter measurement by control devices, including a control and acquisition module, a compression analysis module, a pore analysis module and a permeability analysis module; The control and data acquisition module is used to automatically control the device to conduct experiments and acquire experimental data based on a preset experimental program. The compression analysis module is used to obtain the crude oil compression coefficient based on the experimental data from each experiment. The porosity analysis module is used to measure the core porosity using the compressibility coefficient method based on the experimental data and the crude oil compressibility coefficient. The permeation analysis module is used to extract viscosity and pressure difference data from the experimental data. The stability of viscosity data fluctuations is analyzed within a preset historical neighborhood for each viscosity data point to obtain an instability index for each viscosity data point; the instability index is processed based on fuzzy logic, and combined with the deviation of the differential pressure data at the same moment to obtain the viscosity calibration confidence level; Based on the viscosity calibration confidence level, the viscosity data at each time step are fused with the previous time step to obtain a corrected viscosity value; based on the corrected viscosity value and the experimental data, the permeability is measured using a steady-state method.

2. The apparatus of claim 1, wherein, The method for obtaining the crude oil compressibility coefficient in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes: With a fixed initial pore fluid pressure and a fixed pressure change, all preset temperatures are iterated one by one. In each experiment, the initial pore fluid pressure and the crude oil compressibility coefficient under the corresponding temperature conditions are obtained based on the liquid volume change before and after the pressure increase. The crude oil compressibility coefficient under different temperature and pressure conditions is obtained by changing the initial pore fluid pressure.

3. The apparatus of claim 2, wherein, The method for calculating the compressibility coefficient of crude oil in the in-situ fluid parameter and physical property measurement system for shale oil reservoirs includes: In each experiment, the change in liquid volume before and after the pressure increase is taken as the numerator, the product of the pressure change and the initial total volume of the liquid is taken as the denominator, and the ratio of the fractions is taken as the corresponding crude oil compressibility coefficient.

4. The apparatus of claim 1, wherein, The method for obtaining the core porosity in the in-situ fluid parameter and physical property measurement system for shale oil reservoirs includes: In each experiment, the equivalent volume is obtained based on the change in liquid volume and pressure before and after the pressure increase, combined with the corresponding crude oil compressibility coefficient; the core porosity of the core sample is obtained based on the difference between the equivalent volume and the total liquid volume of the pump and pipeline, combined with the core sample volume.

5. The apparatus of claim 4, wherein, The method for obtaining the equivalent volume in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes: The change in liquid volume before and after the pressure increase is taken as the numerator, and the product of the pressure change and the corresponding crude oil compressibility coefficient is taken as the denominator. The ratio of the fractions is taken as the equivalent volume of the corresponding experiment.

6. The apparatus of claim 1, wherein, The method for obtaining the instability index in the in-situ fluid parameter and property measurement system for shale oil reservoirs includes: For each viscosity data, the CUSUM change point detection algorithm is used to obtain change points in the viscosity data sequence within the preset historical neighborhood, and the viscosity data sequence is divided into subsequences based on the change points; according to the stability of viscosity fluctuations in all subsequences, combined with the number of change points, the instability index corresponding to the viscosity data is obtained.

7. The apparatus of claim 1, wherein, The viscosity calibration confidence level acquisition method in the shale oil reservoir in-situ fluid parameter and physical property measurement system comprises the following steps: a preliminary confidence level of the instability index is evaluated based on fuzzy logic; a difference value between the differential pressure data at each time and a preset differential pressure value is mapped through a preset attenuation function, and a result after mapping is taken as an attenuation factor; the preliminary confidence level corresponding to the viscosity data at each time and the attenuation factor are fused to obtain a viscosity calibration confidence level.

8. The apparatus of claim 1, wherein, The viscosity calibration confidence level acquisition method in the shale oil reservoir in-situ fluid parameter and physical property measurement system comprises the following steps: The viscosity data at each time are weighted by the viscosity calibration confidence level at the same time, a difference value between 1 and the viscosity calibration confidence level is taken to weight the viscosity data at the previous time, and a weighted summation result is taken as a modified viscosity value at each time.

9. The apparatus of claim 1, wherein, The viscosity calibration confidence level acquisition method in the shale oil reservoir in-situ fluid parameter and physical property measurement system comprises the following steps: In each experiment, a modified viscosity value at each time is obtained by processing the modified viscosity value at the current time, a core length, a liquid flow, a core cross-sectional area and a pressure difference between a core injection end and a receiving end based on a steady-state method of Darcy's law under high-temperature and high-pressure conditions of the corresponding experiment.

10. A method for in-situ fluid parameter and property measurement of a shale oil reservoir, the method comprising: The method comprises: performing experiments and collecting experimental data based on a preset experimental program automatic control device; obtaining a crude oil compressibility coefficient according to experimental data of each experiment; measuring core porosity by using a compressibility coefficient method according to the experimental data and the crude oil compressibility coefficient; extracting viscosity and differential pressure data in the experimental data; analyzing fluctuation stability of the viscosity data in a preset historical neighborhood of each viscosity data to obtain an instability index of each viscosity data; obtaining a viscosity calibration confidence level by processing the instability index based on fuzzy logic and combining a deviation of the differential pressure data at the same time; fusing viscosity data at each time and the viscosity data at the previous time based on the viscosity calibration confidence level to obtain a modified viscosity value; and measuring permeability by using a steady-state method based on the modified viscosity value and the experimental data.

11. A method of measuring permeability based on pressure pulse decay, characterized by, The method comprises: performing experiments and collecting experimental data based on a preset experimental program automatic control device; extracting viscosity and differential pressure data in the experimental data; analyzing fluctuation stability of the viscosity data in a preset historical neighborhood of each viscosity data to obtain an instability index of each viscosity data; obtaining a viscosity calibration confidence level by processing the instability index based on fuzzy logic and combining a deviation of the differential pressure data at the same time; fusing viscosity data at each time and the viscosity data at the previous time based on the viscosity calibration confidence level to obtain a modified viscosity value; and measuring permeability by using a pressure pulse attenuation method based on the modified viscosity value and the experimental data.

12. The method of claim 11, wherein, The calculation formula for measuring permeability by using a pressure pulse attenuation method based on the modified viscosity value and the experimental data comprises: ； wherein, is the permeability, which represents the ability of the core to allow fluid to pass through, with the unit of millidarcy mD, is the improved viscosity value at the current acquisition moment, with the unit of Pascal second, is the core length, which represents the flow path length of the fluid in the core, with the unit of m, is the core cross-sectional area, which represents the cross-sectional area of the fluid flow, with the unit of , is the pressure decay constant, which is specifically taken as the inverse of the unit of second, with the unit of 1 / s, is the compressibility of the fluid, which represents the relative change rate of the fluid volume under the unit pressure change, is the volume of the injection end reference chamber, is the volume of the receiving end reference chamber, with the unit of ml.

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