System and method for measuring physical property parameters of fluid in porous medium

Abstract

A system and method for measuring physical property parameters of a fluid in a porous medium. The system for measuring physical property parameters of a fluid in a porous medium comprises: a core device (A), which comprises at least two first-type core modules (A1) and second-type core modules (A2) located between the at least two first-type core modules (A1); an injection device (B); a confining pressure device (C); and a control device (D), which is used for controlling the opening or closing state of a conduit between adjacent core modules, wherein the control device (D) is further configured to calibrate the pore volume of each core on the basis of a balance pressure of when an experimental gas injected into the core device (A) sequentially passes through the core modules (A1, A2), and to record, when a fluid sample injected into the core device (A) saturates the first first-type core module (A1), a balance pressure of when the fluid sample sequentially diffuses to the core modules (A1, A2), thus obtaining physical property parameters of the fluid sample on the basis of the pore volume and the balance pressure.

Description

System and method for measuring physical parameters of fluid in porous media Technical Field

[0001] The present invention relates to the technical field of fluid phase state experiments in oil and gas field development, and in particular to a system and method for measuring physical property parameters of a fluid in a porous medium. Background Art

[0002] Reservoir fluid physical properties are essential data for determining reservoir types, calculating reserves, conducting reservoir engineering and production process research, and formulating development plans. Typically, reservoir fluid physical properties are obtained based on experimental methods specified in the national standard "Analysis Methods for Physical Properties of Reservoir Fluids" (GB / T26981-2020), such as using a PVT cylinder.

[0003] However, with the continuous development of science and technology, experimental technology, experimental equipment and experimental methods are constantly improving. People have gradually discovered that the high-pressure physical properties of formation fluids in porous media in reservoirs are significantly different from the values ​​measured in conventional PVT cylinders. The difference between the two increases with the decrease of the pore size in the porous media in the reservoir.

[0004] Furthermore, patent document CN112214935A, titled "Method and System for Calculating Fluid Phase State in Porous Media," establishes a phase equilibrium calculation model based on experimental results that considers capillary pressure, critical temperature and critical pressure offsets, and pore size distribution in porous media. The paper proposes that porous media significantly influences the phase state of formation fluids when the pore size is less than 100 nm. However, because PVT phase state experiments involve high temperature, high pressure, and a confined environment, clarifying the true phase characteristics of formation fluids in rock cores is extremely difficult.

[0005] Patent document CN105445270A, titled "A Device for Monitoring Fluid Phase Changes in Porous Media," describes a device for monitoring fluid phase changes in porous media. Through windows at both ends of the core holder, the phase changes of the fluid at the core end face can be visually observed. However, this device suffers from a problem: the fluid observed through the windows is no longer in its current state within the porous medium of the core, but rather in its current state within the bulk phase space (similar to the state in a PVT cylinder).

[0006] In addition, in the prior art entitled "A System and Method for Measuring the Bubble Point Pressure of Crude Oil in Porous Media" (CN201910185767.9), a system and method for measuring the bubble point pressure of crude oil in porous media was designed by connecting a long core holder in series with a PVT cylinder. However, a problem with this method is that the core and the PVT cylinder belong to two different media, and the phase states of the fluid in the two media are different. After the connection is completed, the bubble point measured by the PVT cylinder is no longer a phase characteristic of the fluid in the porous medium of the core.

[0007] In summary, most of the current research devices and methods for the phase state of fluids in porous media have some problems. It is impossible to obtain direct measurement parameters that characterize the true state of the fluid in the porous medium, which leads to great limitations in the experimental results and cannot reflect the true situation of the fluid phase state in the core.

[0008] Summary of the Invention

[0009] The purpose of the present invention is to provide a solution for determining the physical property parameters of formation fluids that can reflect the true phase state of the fluids in the core.

[0010] In order to solve the above technical problems, an embodiment of the present invention provides a system for measuring the physical parameters of fluid in a porous medium, comprising: a core device, which includes at least two first-type core modules and a second-type core module located between the at least two first-type core modules, wherein the size of the core in the first-type core module is larger than the size of the core in the second-type core module; a control device, which is used to control the on-off state of the pipeline between adjacent core modules, wherein the control device is further configured to calibrate the pore volume of each core according to the equilibrium pressure of the experimental gas injected into the core device when it passes through each core module in turn, and record the equilibrium pressure when the fluid sample injected into the core device diffuses to each core module in turn when the fluid sample saturates the first first-type core module, thereby obtaining the physical parameters of the fluid sample based on the pore volume and the equilibrium pressure.

[0011] Preferably, the system also includes an injection device, wherein the injection device is configured to inject a first experimental gas into the first first-type core module during the pore volume calibration stage, and to inject a second experimental gas and a fluid sample during the constant mass expansion stage, wherein the fluid sample is used to simulate the fluid in the downhole porous medium formation.

[0012] Preferably, the system further comprises a temperature control device for providing the core device with a simulated formation temperature.

[0013] Preferably, the system further comprises a confining pressure device, which is in communication with the core sidewalls in each of the core modules.

[0014] Preferably, the core modules are connected in series through a high-pressure pipeline, wherein a connecting valve is provided at the end of each core module, and a pressure sensor is provided at each connecting valve, wherein the system also includes a back pressure device hung at the outlet of the first first-type core module.

[0015] Preferably, the control device is configured to, during the pore volume calibration stage: open only the connecting valve for connecting the injection device and the first core, record the gas volume of the first experimental gas injected into the first core and the first value of the first equilibrium pressure, open the connecting valve for connecting the first core and the second core, record the second value of the first equilibrium pressure, open the connecting valves for connecting each core module in turn, record other values ​​of the first equilibrium pressure respectively, and obtain the pore volume of each core according to the first value, second value and other values ​​of the first equilibrium pressure.

[0016] Preferably, the control device is further configured to: during the constant mass expansion stage, only open the connecting valve connecting the injection device and the first core, inject the second experimental gas into the first core, adjust the back pressure device so that the pressure of the first core rises to a preset formation pressure, allow the fluid sample to be injected into the first core to saturate the first core, then close the connecting valve connecting the injection device and the first core, open the connecting valve connecting the first core and the second core, allow the fluid sample in the first core to diffuse into the second core, record the first value of the second equilibrium pressure, open the connecting valve connecting each core in turn, record other values ​​of the second equilibrium pressure, and calculate the physical properties of the fluid sample based on the first value and other values ​​of the second equilibrium pressure and the pore volume of each core.

[0017] Preferably, the physical property parameters include saturation pressure, wherein the control device is further configured to draw a curve representing the relationship between pressure and pore volume during core expansion, and obtain the saturation pressure of the fluid sample by identifying the inflection point in the curve.

[0018] Preferably, the control device is further configured to, in the step of calibrating the pore volume of each core, subtract the volume of all high-pressure pipelines located at the front end of the corresponding core from the pore volume of each core.

[0019] Preferably, the control device is also configured to determine the number of the first type core modules and the second type core modules through the following steps: performing a PVT phase experiment on the fluid sample, determining the dissolved gas-oil ratio of the formation fluid in the PVT tube, the saturation pressure based on the PVT experiment, and the pressure-volume relationship curve; according to the PV relationship in the pressure-volume relationship curve where the pressure is greater than the saturation pressure based on the PVT experiment, calculating the pressure drop value corresponding to each unit increase in the core pore volume of the formation fluid sample, and based on this, calculating the number of the second type core samples required to drop from the actual formation pressure to the saturation pressure based on the PVT experiment; calculating the number of the first type core samples required to drop from the saturation pressure based on the PVT experiment to the final pressure, wherein the final pressure is the pressure corresponding to 3 times the initial fluid volume required to saturate the first type core sample.

[0020] Preferably, the system also includes an oil and gas recovery device hung at the outlet of the first first-type core module, wherein the control device is also configured to obtain gas-oil ratio data from the oil and gas recovery device, and determine the timing for completing formation fluid saturation based on the changing state of the gas-oil ratio data.

[0021] On the other hand, a method for determining the physical properties of a fluid in a porous medium is provided, and the method is implemented using the system as described above, wherein the method includes: injecting a first experimental gas into a first first-type core module; controlling the on-off state of a pipeline between adjacent core modules by the control device, and continuously recording the equilibrium pressure when the first experimental gas passes through each core module in turn, thereby calibrating the pore volume of each core; injecting a second experimental gas and a fluid sample into the core device respectively; when the fluid sample saturates the first first-type core module, controlling the on-off state of a pipeline between adjacent core modules by the control device, and continuously recording the equilibrium pressure when the fluid sample diffuses to each core module in turn, and obtaining the physical properties of the fluid sample in combination with the pore volume of each core.

[0022] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0023] The present invention proposes a system and method for measuring the physical properties of fluids in porous media. The system and method are mainly composed of multiple full-diameter cores and short cores connected in series, and are used to simulate the process of constant mass expansion of formation fluids in a reservoir. By directly measuring the pressure of the fluid during its expansion in the core and its corresponding volume, high-pressure physical properties such as the saturation pressure of the formation fluid are determined. As a result, the present invention can directly measure the relationship between the pressure and pore volume of the formation fluid during its expansion in the porous medium of an actual reservoir, accurately obtain high-pressure physical properties such as the saturation pressure, deviation coefficient, compressibility coefficient, and volume coefficient of the fluid in the core, clarify the true phase characteristics of the formation fluid in the porous medium of the reservoir, and provide objective basic parameters for the development plan design, reserve calculation, and oil and gas test production of low-porosity and low-permeability oil and gas reservoirs, which has extremely broad promotion and application value.

[0024] Other features and advantages of the present invention will be described in the following description, and in part will become apparent from the description, or will be understood by practicing the present invention. The purposes and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0026] FIG1 is a schematic diagram of the overall structure of a system for measuring physical parameters of a fluid in a porous medium according to an embodiment of the present application.

[0027] FIG2 is a schematic diagram of the specific structure of a system for measuring physical parameters of a fluid in a porous medium according to an embodiment of the present application.

[0028] FIG3 is a schematic diagram of an implementation flow of a system for measuring physical parameters of a fluid in a porous medium according to an embodiment of the present application.

[0029] FIG4 is a schematic diagram showing the comparison of PV relationship curves measured by a system for measuring physical properties of a fluid in a porous medium according to an embodiment of the present application and a traditional PVT cylinder.

[0030] FIG5 is a schematic diagram showing the comparison of the inflection points in the PV relationship curves measured by the system for measuring the physical properties of a fluid in a porous medium according to an embodiment of the present application and a traditional PVT cylinder.

[0031] FIG6 is a schematic diagram of the steps of a method for measuring physical parameters of a fluid in a porous medium according to an embodiment of the present application. DETAILED DESCRIPTION

[0032] The following describes the embodiments of the present invention in detail with reference to the accompanying drawings and examples, so that the present invention can fully understand how to apply technical means to solve technical problems and achieve technical effects, and thus implement the invention accordingly. It should be noted that, as long as no conflict exists, the various embodiments of the present invention and the various features of the embodiments can be combined with each other, and the resulting technical solutions are all within the scope of protection of the present invention.

[0033] In addition, the steps shown in the flowchart of the accompanying drawings can be executed in a computer system such as a set of computer executable instructions. Also, although a logical order is shown in the flowchart, in some cases, the steps shown or described can be performed in a different order than here.

[0034] The terms used herein are intended only to describe specific embodiments and are not intended to limit exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms "a", "an", "an item" used herein are also intended to include the plural. It should also be understood that the terms "comprise" and / or "include" used herein specify the presence of stated features, integers, steps, operations, units and / or components, and do not preclude the presence or addition of one or more other features, integers, steps, operations, units, components and / or combinations thereof.

[0035] To address one or more technical issues in the prior art, this application proposes a system and method for measuring the physical properties of fluids in porous media. This system and method accurately obtains the true high-pressure physical properties of fluids in porous reservoir media, clarifying the true phase characteristics of the fluids in the formation, thereby providing accurate data support for determining oil and gas reservoir types, calculating reserves, and formulating reservoir engineering development plans.

[0036] Figure 1 is a schematic diagram of the overall structure of a system for measuring the physical properties of a fluid in a porous medium according to an embodiment of the present application. As shown in Figure 1 , the system for measuring the physical properties of a fluid in a porous medium according to an embodiment of the present invention (also referred to as a "physical property measurement system") includes: a core device A, an injection device B, a confining pressure device C, and a control device D.

[0037] The core assembly A includes at least two first-type core modules A1 and a second-type core module A2 positioned between the at least two first-type core modules. In embodiments of the present invention, the number of second-type core modules A2 can be one or more. When multiple second-type core modules A2 are configured, they are connected in series. The first-type core module A1 contains the first-type core 2, and the second-type core module A2 contains the second-type core 4 (see Figure 2).

[0038] In an embodiment of the present invention, each core module is connected in series via a high-pressure serial pipeline. First, several second-type core modules A2 are connected in series via the high-pressure serial pipeline to form a second-type core module sequence. Then, at least two first-type core modules A1 are respectively positioned at the end faces of the second-type core module sequence. That is, one first-type core module A1 is positioned at the end face at the entrance of the second-type core module sequence, and the remaining first-type core modules A1 are positioned at the end faces at the exit of the second-type core module sequence. Similarly, a first-type core module A1 is connected in series with its adjacent second-type core module A2 via a high-pressure serial pipeline. In this embodiment of the present invention, the end faces of the cores in adjacent core modules are positioned relative to each other.

[0039] In this embodiment of the present invention, the core size of the first type core module A1 is larger than the core size of the second type core module A2. Core size includes core diameter and core length. Specifically, the core diameter of the first type core module A1 is larger than the core diameter of the second type core module A2, and the core length of the first type core module A1 is larger than the core length of the second type core module A2.

[0040] Injection device B is connected to the inlet of the first first-type core module A1 within core assembly A via a high-pressure injection pipeline 22 (see Figure 2 ). Furthermore, as shown in Figure 2 , a high-pressure output pipeline 29 is provided at the outlet of the last first-type core module A1 within core assembly A. Injection device B is used to inject the experimental gases and fluid samples required for the experiment. Injection device B is used to inject the first experimental gas during the pore volume calibration phase and the second experimental gas and formation fluid sample during the constant mass expansion experiment phase.

[0041] In this embodiment of the present invention, the core device A is used to simulate the porous medium environment of a downhole formation. The fluid sample (also referred to as a "formation fluid sample") is used to simulate the fluid in the downhole porous medium formation, thereby simulating the physical properties of the sample under the high temperature and high pressure environment of the porous medium.

[0042] The confining pressure device C is connected to the core sidewall of each core module A1 and A2 in the core assembly A. The confining pressure device C is used to provide simulated confining pressure to each core module A1 and A2 in the core assembly A, thereby simulating the compression state of the overburden rock pressure actually experienced by the sample core in the formation.

[0043] The control device D is used to control the on / off status of the pipelines between adjacent core modules A1 and A2. In other words, the control device D is used to control the on / off status of the high-pressure pipelines (including the high-pressure series pipeline, the high-pressure injection pipeline, and the high-pressure output pipeline) at the end faces of each core module A1 and A2.

[0044] Control device D continuously records the equilibrium pressure (recorded as the first equilibrium pressure) when the first experimental gas passes through each core module A1 and A2 at different locations by controlling the on / off status of the pipelines between adjacent core modules A1 and A2, thereby calibrating the pore volume of each core. Furthermore, control device D also controls the on / off status of the pipelines between adjacent core modules A1 and A2, while controlling the formation fluid sample injected into core device A to saturate the first first-type core module A1. It continuously records the equilibrium pressure (recorded as the second equilibrium pressure) when the formation fluid sample diffuses to each core module A1 and A2 at different locations. Combined with the pore volume of each core, the physical properties of the formation fluid sample are ultimately obtained.

[0045] In this way, the present invention achieves accurate measurement of the pressure of a high-pressure fluid sample in a constant-quality expansion process in a rock core and its corresponding pore volume.

[0046] FIG2 is a schematic diagram of the specific structure of the system for measuring the physical property parameters of a fluid in a porous medium according to an embodiment of the present application.

[0047] As shown in Figure 2, the first type core module A1 includes: a first type core 2, core clamps 1, 10 (full diameter core clamps) and a core casing 6. In one embodiment, the size range of the first type core is a core diameter of 8-10 cm and a core length of 3-15 cm. The second type core module A2 includes: a second type core 4, core clamps 3, 5, 7, 8, 9 (short core clamps) and a core casing 6. In one embodiment, the size range of the second type core is a core diameter of 1.8-3.8 cm and a core length of 1-15 cm. The structures of the full diameter core clamp, the short core clamp and the core casing, as well as the clamping method of the core in these core clamps are well known to those skilled in the art and will not be described in detail here.

[0048] A corresponding connecting valve 11, 13, 15, 16, 17, etc. is installed at the end 18 of each core module A1 and A2. Specifically, a corresponding connecting valve is installed on each high-pressure series pipeline, high-pressure injection pipeline, and high-pressure output pipeline to connect the core modules in series. In this embodiment of the present invention, the connecting valve on each high-pressure series pipeline, high-pressure injection pipeline, and high-pressure output pipeline is a three-way valve.

[0049] Full-diameter core holders 1 and 10 are used to hold full-diameter cores 2. The first type of core 2 is wrapped in a flexible tube (rubber tube or high-pressure heat-shrink tubing) 6, leaving only the two end faces of the core exposed. The full-diameter core 2 in full-diameter core holder 1 is first saturated with high-pressure formation fluid, and then the fluid within the full-diameter core 2 is expanded and diffused into the cores in the remaining holders. The full-diameter core 2 is chosen for the first core because it has a large pore volume and saturates a large amount of formation fluid, facilitating subsequent expansion. Once fully saturated with formation fluid, the full-diameter core 2 in full-diameter core holder 1 is connected to a connecting valve 13 via a 1 / 16-inch high-pressure serial line 12, and then to a short core holder 3. The short core holders 3, 5, 7, 8, and 9 are used to hold short cores 4. The second type of core 4 is also wrapped in a flexible tube (rubber tube or high-pressure heat-shrink tubing) 6, leaving only the two end faces of the core exposed. The short core holders 3, 5, 7, 8, and 9 are connected in series in sequence through a 1 / 16-inch high-pressure pipeline 12 and a connecting valve 13.

[0050] It should be noted that the present invention does not specifically limit the number of the first type of core modules A1 and the number of the second type of core modules A2. Those skilled in the art can adjust the number of full-diameter cores and short cores according to the experimental pressure (formation pressure and saturation pressure) and the required expansion volume.

[0051] In the embodiment of the present invention, the high-pressure connecting pipeline 12 is preferably a 1 / 16-inch high-pressure pipeline 12. Such pipelines are required to be as short as possible, wherein the length of each high-pressure series pipeline 12 is preferably 3-5 cm to ensure that the volume in the pipeline is as small as possible.

[0052] Referring to Figure 2, the injection device B includes a double-cylinder plunger pump 19 and a piston container 21. The two plunger pumps within the double-cylinder plunger pump 19 are connected to two storage containers within the piston container 21 via corresponding two-way valves 20. The double-cylinder plunger pump 19 is used to transmit pressure to the piston container via a pressurized medium. The piston container 21 is used to utilize the pressure power provided to inject the first experimental gas required for the pore volume calibration phase into the first first-type core module A1, and to inject the second experimental gas and formation fluid sample during the constant mass expansion phase. The first experimental gas is preferably helium. The second experimental gas is preferably natural gas.

[0053] Specifically, the double-cylinder plunger pump 19 is used to provide driving power to the piston container 21, and the pressure in the double-cylinder plunger pump 19 is transmitted to the piston container 21 through distilled water as the pressure medium, so that the piston pushes the first experimental gas or the second experimental gas or the formation fluid sample into the full-diameter core clamp 1.

[0054] The confining pressure device C is connected to the sidewalls of the cores within each core module A1 and A2. It utilizes a dual-cylinder plunger pump 28. Specifically, the dual-cylinder plunger pump 28 within the confining pressure device C is connected to each core module A1 and A2 via a high-pressure injection line 22 connected to each core sidewall. The dual-cylinder plunger pump 28 applies pressure to the flexible tube 6 encasing the core to simulate the pressure exerted by the overburden on the core. The pressure medium is distilled water.

[0055] In addition, the core casing 6 is a heating casing. To this end, the physical property parameter measurement system described in this embodiment of the present invention further includes a temperature control device 27. This temperature control device is used to provide simulated formation temperatures to each core module A1 and A2 within the core assembly A. In one embodiment, the temperature control device is a temperature control box 27. Specifically, the core holder is wrapped in a heating casing 6, and the temperature of the heating casing is controlled by the temperature control box 27, thereby controlling and regulating the core temperature so that the temperature of each core matches the actual formation temperature.

[0056] In addition, the physical property parameter measurement system described in this embodiment of the present invention also includes a back-pressure device (unnumbered) attached to the outlet of the first first-type core module A1. The back-pressure device includes a back-pressure pump 23 and a back-pressure valve 25. The back-pressure pump 23 is a single-cylinder plunger pump. Specifically, the single-cylinder plunger pump 23 is used to provide pressure to the back-pressure valve 25, thereby regulating the pressure at the outlet of the full-diameter core holder 1 by controlling the back-pressure valve 25.

[0057] In this embodiment of the present invention, a two-way valve 14 is provided at the front end of the back-pressure valve 25. The two-way valve 14 controls the communication between the back-pressure device and the first first-type core module A1. Specifically, the two-way valve 14 is provided at the front end of the back-pressure valve 25. The control device D controls the two-way valve 14 to further control the switching between the full-diameter core 2 and the three-way valve 13 after saturation of the formation fluid. When the two-way valve 14 is open, the full-diameter core 2 is saturated; once saturation is complete, the two-way valve 14 is closed.

[0058] Furthermore, the physical property parameter measurement system described in this embodiment of the present invention also includes an oil and gas recovery device (not numbered) attached to the outlet of the first first-type core module A1. The oil and gas recovery device is attached to the rear end of the back-pressure valve 25 within the back-pressure device. The oil and gas recovery device includes an oil-gas separation bottle 24 and a gas meter 26.

[0059] In addition, a pressure sensor 18 for measuring the equilibrium pressure is arranged at each connecting valve provided at the end face of each core module A1 and A2, thereby forming a pressure monitoring group. The pressure monitoring group (including pressure sensors connected to three-way valves 11, 13, 15, 16, etc.) is used to measure the pressure at both ends of all full-diameter cores and short cores. Each pressure sensor 18 is connected to the three-way valves 11, 13, 15, 16, 17, etc. at the corresponding position. For example, in an embodiment of the present invention, the switch of the three-way valve 11 only controls the connection of the two (pipeline) connecting ports of the valve, and does not control the connection of the pressure sensor 18. That is, the pressure sensor 18 is always connected to one of the pipeline connecting ports of the three-way valve 11, and is connected to the other pipeline connecting port of the three-way valve 11 after the valve is opened. In this way, the volume of the connecting pipeline between the core clamps can be reduced, thereby ensuring the accuracy of the experimental results.

[0060] FIG3 is a schematic diagram of the implementation process of the system for measuring the physical property parameters of the fluid in the porous medium according to the embodiment of the present application.

[0061] Before the system is set up (before the experiment begins), the number of the first type core modules and the second type core modules A1 and A2 is configured through the control device D.

[0062] Control device D configures the number of first- and second-type core modules, respectively, according to the following steps. Specifically, a PVT phase state experiment is first conducted on the formation fluid sample to determine the dissolved gas-oil ratio of the formation fluid in the PVT cylinder, the saturation pressure based on the PVT experiment, and the pressure-volume relationship curve. Furthermore, the porosity and permeability of the first and second-type core samples are determined using core analysis methods. Then, based on the PV relationship in the measured pressure-volume relationship curve, where the pressure is greater than the saturation pressure based on the PVT experiment, the pressure drop corresponding to each unit increase in core pore volume of the formation fluid sample is calculated. Based on the corresponding pressure drop per unit increase in core pore volume, the number of second-type core samples required to reduce the actual formation pressure to the saturation pressure based on the PVT experiment is calculated. Finally, the number of first-type core samples required to reduce the saturation pressure based on the PVT experiment to the final pressure is calculated, where the final pressure is the pressure corresponding to when the volume of the injected fluid sample reaches three times the initial fluid volume required to saturate the first-type core sample.

[0063] Specifically, before the experiment begins, a PVT phase state test is performed on the formation fluid samples in accordance with the national standard "Physical Property Analysis Method for Oil and Gas Reservoir Fluids" (GB / T26981-2020) to determine parameters such as the dissolved gas-oil ratio, saturation pressure, and pressure-volume (PV) curve of the formation fluid in the PVT cylinder. Furthermore, the porosity and permeability of several core samples, including the full-diameter core 2 and short core 4, must be measured according to the national standard "Core Analysis Method" (GB / T 29172-2012). Then, based on the saturation pressure measured by the PVT experiment, the saturation pressure differential (i.e., the difference between the formation pressure and the saturation pressure) was calculated. Combined with the pressure-volume (PV) relationship of the formation fluid sample, where the pressure is greater than the saturation pressure, the corresponding pressure drop for each increase in the core pore volume with the formation fluid sample volume was calculated. Combined with the porosity and permeability of the four short core samples, the number of short cores required to reduce the initial formation pressure to the saturation pressure measured by the PVT experiment (PVT cylinder measurement) was further calculated. Furthermore, based on the porosity and permeability of the two full-diameter core samples, the number of first-class core samples required to continue reducing the pressure in the PV curve from the saturation pressure to the final pressure (i.e., the pressure corresponding to three times the initial fluid volume) was calculated.

[0064] It is important to note that when the pressure is greater than the saturation pressure, a short core with the smallest possible pore volume should be selected to avoid excessive pore volume causing the pressure to drop too quickly, thereby directly skipping the saturation pressure. When the pressure is less than the saturation pressure, a long core or a full-diameter core with a large pore volume can be selected to quickly reduce the pressure to the final pressure. To this end, the embodiment of the present invention conducts fluid saturation pressure measurement experiments by providing a core device formed by at least two first-type core modules and several core modules located between the at least two first-type core modules. This effectively controls the rate of pressure change and improves the accuracy of the final measurement results.

[0065] Then, the control device D first controls the experiment of calibrating the pore volume of each core under the action of confining pressure.

[0066] In one embodiment, the control device D is further configured to:

[0067] Only the connecting valve 11 for connecting the injection device and the first core is opened, and the first experimental gas is first injected from the inlet of the core device A, and the gas volume of the first experimental gas injected into the first core and the first value of the first equilibrium pressure are recorded.

[0068] Open the connecting valve 13 for connecting the first core and the second core, record the second value of the first equilibrium pressure,

[0069] Open the connecting valves 15, 16, etc. for connecting the core modules A1, A2 in sequence, and record the other values ​​of the first equilibrium pressure respectively.

[0070] The pore volume of each core is obtained according to the first value, the second value and other values ​​of the first equilibrium pressure.

[0071] Specifically, the control device D carries out the core pore volume calibration experiment according to the following steps:

[0072] Control the confining pressure device C to apply confining pressure to each core module A1 and A2;

[0073] Control the connecting valves set on the end faces of each core module A1 and A2 to open, thereby vacuuming all cores;

[0074] Control the closing of the connecting valves for connecting the core modules A1 and A2 in series;

[0075] Controlling the injection device B to inject the first experimental gas from the inlet of the core device A, and recording the volume of the gas injected into the first core and the first equilibrium pressure after the pressure stabilizes;

[0076] Controlling the connecting valve for connecting the first core and the second core to open, and recording the current first equilibrium pressure after the pressure stabilizes;

[0077] Similarly, the first equilibrium pressure after the pressure stabilizes is recorded respectively by sequentially controlling the opening of the connecting valves for the core modules connected in series;

[0078] The pore volume of each core was obtained based on the first equilibrium pressure recorded at different time periods.

[0079] Specifically, S1, the control device D opens all valves that control the confining pressure of the core holder, allowing the pressure generated by the double-cylinder plunger pump 28 to be transmitted to each core holder, applying confining pressure to the overlying rock pressure of the formation; S2, the control device D opens and controls all valves 11, 13, 15, 16, etc. set on the end face of each core module; S3, the control device D controls all cores to be vacuumed at the same time from the three-way valves 11 and 17 respectively, until the control device D detects that the readings of the pressure sensors (with readings) corresponding to all cores are consistent; S4, the control device D closes all valves 13, 15, 16, etc. used to connect the core holders in series, thereby disconnecting the core in each section of the core holder; S5, under the control of the control device D, the injection device B injects helium at constant pressure into the full-diameter core 2 from the three-way valve 11, and the control device D records the constant pressure entering the rock The volume of helium V1 in the core 2 and the pressure P1 in the core 2 (the pressure at the valve 11) are recorded after the pressure at the valve 11 stabilizes. S6. The control device D opens the three-way valve 13 again until the pressures in the core holders 1 and 3 stabilize (i.e., the pressures at the front ends of the first and second cores) and remain consistent. At this time, the control device D records the current equilibrium pressure as P2, and then calculates the pore volume V2 of the short core 4 using the formula V2=Z2·P1·V1 / (Z1·P2)-V1 (wherein, this formula is derived from PV=ZnRT, where Z1 and Z2 represent the deviation factors of helium at P1 and P2, respectively, which can be obtained by looking up the table). Next, S6. The three-way valve 15 is opened again, and the aforementioned step S6 and calculation formula are repeated to calculate the pore volume of the core in the core holder 5. After the pore volumes of all cores are calculated, the calibration experiment is stopped.

[0080] Next, the control device D continues to control the saturated formation fluid experiment and fluid physical property parameter measurement experiment of the full-diameter core 2 under the action of confining pressure.

[0081] In one embodiment, the control device D is further configured to:

[0082] Only the connecting valve 11 for connecting the injection device B and the first core is opened, and the second experimental gas is first injected from the inlet of the core device A and then injected into the first core.

[0083] Adjust the back pressure device so that the pressure of the first core reaches the preset formation pressure.

[0084] Allow the fluid sample to be injected into the first core from the inlet of the core device A to saturate the first core, and then close the connecting valve 11 connecting the injection device B and the first core.

[0085] Open the connecting valve 13 for connecting the first core and the second core, so that the fluid sample in the first core diffuses into the second core, and record the first value of the current second equilibrium pressure.

[0086] Open the connecting valves 15, 16, etc. for connecting the core modules in sequence, and record the other values ​​of the second equilibrium pressure respectively.

[0087] The physical property parameters of the fluid sample are calculated according to the first value and other values ​​of the second equilibrium pressure and the pore volume of each core.

[0088] Specifically, the control device D carries out the constant quality expansion experiment according to the following steps:

[0089] Control the connecting valves set on the end faces of each core module A1 and A2 to open, thereby vacuuming all cores;

[0090] Control the closing of the connecting valves for connecting the core modules A1 and A2 in series;

[0091] Control the injection device B to inject the second experimental gas from the inlet of the core device A, and control the back pressure device to increase the pressure of the first core to the preset formation pressure;

[0092] Controlling the injection device B to inject the formation fluid sample from the inlet of the core device A so that the formation fluid sample displaces the first core block to complete the formation fluid saturation;

[0093] Control the valve at the inlet of the core device A to close;

[0094] Controlling the opening of a connecting valve for connecting the first core and the second core to allow the formation fluid in the first core to diffuse into the second core, and recording the current second equilibrium pressure after the pressure stabilizes;

[0095] Similarly, the connecting valves for the core modules A1 and A2 connected in series are controlled to open in sequence, and the second equilibrium pressure after the pressure is stabilized is recorded respectively;

[0096] The high-pressure physical properties of the formation fluid samples are calculated based on the second equilibrium pressure at different time periods and the pore volume of each core.

[0097] In one embodiment, the physical property parameter includes saturation pressure. Specifically, during the calculation of the saturation pressure, the control device is further configured to plot a curve representing the relationship between pressure and pore volume during the core expansion process based on the second equilibrium pressure at different time periods and the pore volume of each core, thereby obtaining the saturation pressure of the formation fluid sample by identifying an inflection point in the current pressure-pore volume relationship curve.

[0098] Specifically, M1. The control device D re-evacuates all the cores in series, and the vacuuming method refers to the above steps S1 to S3; M2. The control device D closes all valves 13, 15, 16, etc. used for the core clamps in series, thereby disconnecting the core in each core clamp; M3. Under the control of the control device D, the three-way valve 11 and the two-way valve 14 are opened, and then, the double-cylinder plunger pump 19 is used to inject natural gas into the full-diameter core 2 to fully saturate the natural gas. At the same time, the single-cylinder plunger pump 23 is adjusted by controlling the back pressure valve 25 to increase the pressure of the core 2 (according to the pressure at the valve 11) to the formation pressure; M4. Under the control of the control device D, the injection device B injects a formation fluid sample into the full-diameter core 2 from the three-way valve 11, so that the formation fluid displaces the natural gas and completes the saturation of the formation fluid.

[0099] In one embodiment, the control device D is further configured to obtain gas-to-oil ratio data from the oil and gas recovery device and determine when formation fluid saturation has been completed based on the current state of the gas-to-oil ratio data. Specifically, when the output gas-to-oil ratio measured by the oil-gas separator 24 and the gas meter 26 remains unchanged, the formation fluid saturation task is determined to be completed.

[0100] Next, M5, when the full-diameter core 2 is saturated with formation fluid, the control device D closes the three-way valve 11 and the two-way valve 14; M6, the control device D opens the three-way valve 13 to allow the formation fluid sample in the full-diameter core 2 to diffuse into the short core 4. When the port pressures of the full-diameter core 2 and the short core 4 are consistent, that is, when the pressure sensor reading at valve 11 is consistent with the pressure sensor readings at valves 13 and 15 (at this time, the three-way valve 15 is in a closed state, but the pipeline connection port connected to the pressure sensor is connected to the one-way pipeline connection port connected to the core holder 3, that is, although the valve 15 is in a closed state, the pressure sensor at valve 15 can still measure the pressure at the outlet of the core holder 3), the control device D records the pressure at this time and records it as the second equilibrium pressure; M7, the control device D opens the three-way valve 15 again to allow the formation fluid sample to diffuse into the short core 4 again. In the core of the core holder 5, when the port pressures of the full-diameter core 2, the short core 4 and the second short core are consistent, that is, when the pressure sensor readings at valves 11, 13, 15 and 16 are consistent, the control device D records the pressure at this time and records it as the second equilibrium pressure; M8, repeat the above step M7 again to allow the formation fluid sample to diffuse to the next core, and the control device D records the corresponding second equilibrium pressure until the formation fluid sample enters the last full-diameter core and the second equilibrium pressure is recorded. The current constant mass expansion experiment ends; M9, according to the (second) equilibrium pressure of the formation fluid expansion in each core obtained in steps M6-M8 and its corresponding core pore volume, the corresponding relationship between the pressure and pore volume of the formation fluid during the expansion process in the core is obtained, and the saturation pressure of the current formation fluid sample in the core is determined by the inflection point of the current pressure-pore volume curve. In addition, the present invention can also calculate other reasonable parameters such as the deviation coefficient, compressibility coefficient and volume coefficient of the formation fluid sample in the core, wherein the calculation method refers to the national standard "Core Analysis Method" (GB / T 29172-2012).

[0101] Furthermore, since the aforementioned calibrated pore volume of each core includes the volume of the fluid in the 1 / 16-inch high-pressure serial pipeline 12, although the internal volume of the 1 / 16-inch high-pressure pipeline is very small, it will still affect the measurement results. Therefore, in the step of calibrating the pore volume of each core in the embodiment of the present invention, the control device D is further configured to subtract the (total) volume of all high-pressure pipelines located at the front end of the corresponding core from the pore volume of each core when calibrating the pore volume of each core, that is, it is necessary to eliminate the impact of the volume of the high-pressure serial pipeline on the measurement results.

[0102] Specifically, in the above step M9, when the formation fluid sample enters the nth core, the actual fluid volume in the corresponding core should be the total pore volume of the n cores (the volume calibrated by helium) minus the volume of (n-1) high-pressure series pipelines (the pipeline volume is calculated by measuring the pipeline length).

[0103] In this way, through the implementation process method of the above-mentioned physical property parameter measurement system, the embodiment of the present invention can utilize the setting of a specific core distribution structure (setting long cores at both ends of multiple short cores in series) to not only accurately measure the permeability of core modules of different sizes; but also based on the pore permeability (pore volume) of each level of core measured by this specific core distribution structure, by conducting constant mass expansion experiments, more accurate fluid physical property parameters are obtained when the pressure change (depressurization) rate during the fluid diffusion process is controllable.

[0104] The physical property parameter measurement system of the present invention is described below by applying the implementation process of the physical property parameter measurement system of the present invention to a specific oil field.

[0105] The average permeability of a certain oil field reservoir is about 0.11×10 -3 μm 2 The average porosity is 6.8%, indicating a tight sandstone reservoir. The formation fluid is a condensate gas reservoir, with a formation temperature of 110°C and a formation pressure of 32 MPa. The phase characteristics of the condensate gas in the reservoir differ from those measured in the PVT cylinder, necessitating further measurement of the dew point pressure of the condensate gas in the reservoir.

[0106] (1) Before the experiment, the PVT phase state test of the condensate gas sample was carried out according to the national standard "Analysis Method of Physical Properties of Oil and Gas Reservoir Fluids" (GB / T26981-2020). The dew point pressure was measured to be 26.36 MPa and the dissolved gas-oil ratio was 3934 m 3 / m 3 , and a pressure-volume (PV) curve was obtained. Furthermore, the porosity and permeability of several core samples, including full-diameter cores and short cores, were measured according to the national standard "Core Analysis Method" (GB / T29172-2012).

[0107] (2) Calculate the number of core samples required. Based on the dew point pressure, the ground pressure difference was calculated to be 5.7 MPa. Based on the pressure-volume relationship in the PV relationship curve, 11 cores that met the required pore volume requirements were selected from the candidate cores, including 3 full-diameter cores and 8 short cores. Specific core parameters are shown in Table 1.

[0108] Table 1 Core parameters

[0109] (3) Calibrate the pore volume of the core in each core holder under the action of confining pressure. First, open all valves that control the confining pressure of the core holder, and allow the pressure generated by the double-cylinder plunger pump 28 to be transmitted to each core holder, and add confining pressure to the pressure of the overlying rock of the formation. And open all valves 13, 15, 16, etc. of the core holders in series. Simultaneously vacuum all cores from three-way valves 11 and 17 until the pressure sensor readings corresponding to all cores are consistent. Then close all valves 13, 15, 16, etc. of the core holders in series, and disconnect the core in each section of the core holder. From the three-way valve 11, inject helium at a constant pressure of 5MPa into the full-diameter core 2, record the volume V1 of helium entering the core 2 at constant pressure, and record the pressure P1 in the core 2 when the pressure stabilizes. Then, open three-way valve 13 until the pressures in core holders 1 and 3 stabilize and remain consistent. Record the equilibrium pressure at this point as P2. Calculate the pore volume V2 of short core 4 using the formula V2 = Z2·P1·V1 / (Z1·P2)-V1. Then, open three-way valve 15 again and repeat the above steps and calculation formula to calculate the pore volume of the core in core holder 5. The calibration experiment ends when the pore volumes of all cores have been calculated. The pore volumes of the cores under calibrated confining pressure are shown in Table 1.

[0110] (4) The full-diameter core 2 is saturated with formation fluid. First, all the cores in series are vacuumed again. The vacuuming method is as described in step (3). Then, the valves of all the cores in series are closed. Open the three-way valve 11 and the two-way valve 14, and use the double-cylinder plunger pump 19 to fully saturate the full-diameter core (core No. 1 in Table 1) with natural gas. The back pressure valve 25 is adjusted by the single-cylinder plunger pump 23 to raise the core pressure to the formation pressure of 32 MPa. Then, the condensate gas is used to displace the natural gas to complete the saturation of the condensate gas. When the output gas-oil ratio measured by the oil-gas separation bottle 24 and the gas meter 26 remains unchanged, the saturation of the condensate gas is completed.

[0111] (5) Determine the dew point pressure of the condensate gas in the core. When the full-diameter core (core number 1 in Table 1) is saturated with condensate gas, close the three-way valve 11 and the two-way valve 14. Open the three-way valve 13 to allow the condensate gas in the full-diameter core (core number 1 in Table 1) to diffuse into the short core (core number 2 in Table 1). When the pressure sensor reading at valve 11 is consistent with the pressure sensor readings at valves 13 and 15, record the pressure at this time. Then open the three-way valve 15 again and allow the condensate gas to diffuse into the core number 3 again. When the pressure sensor readings at valves 11, 13, 15 and 16 are consistent, record the pressure value. Then repeat the above steps again to allow the condensate gas to diffuse into the next core. The experiment ends when the condensate gas enters the last full-diameter core (core number 11 in Table 1).

[0112] Experimental results:

[0113] Table 1 shows the relationship between core pressure and its corresponding cumulative core pore volume (including the corrected volume after subtracting dead volume in the pipeline) during the constant-mass expansion of condensate gas. Plotting the core pressure and the corrected cumulative core pore volume in the same coordinate system yields the pressure-volume (PV) curve measured in the core, as shown in Figure 4. Another curve represents the PV curve measured in a PVT cylinder, which serves as a reference for comparison. To determine the inflection points of the two different curves in Figure 4, each curve is magnified to produce Figures 5(a) and 5(b). Figure 5(a) shows the inflection point of the magnified PV curve measured in the PVT cylinder. The pressure corresponding to the inflection point is the dew point pressure of 26.36 MPa measured in the PVT cylinder. Figure 5(b) shows the inflection point of the magnified PVT curve measured in the core. The pressure corresponding to the inflection point is the dew point pressure of 28.23 MPa measured in the core. Comparing the two dew point pressures, it was found that the dew point pressure of condensate gas measured in the core was higher than that measured in the PVT cylinder, indicating that the presence of porous media can increase the dew point pressure of condensate gas by 7.1%.

[0114] On the other hand, based on the above-mentioned physical property parameter measurement system, an embodiment of the present invention further provides a method for measuring the physical property parameters of a fluid in a porous medium (also referred to as a "physical property parameter measurement method"). The physical property parameter measurement method is implemented using the above-mentioned physical property parameter measurement system.

[0115] FIG6 is a schematic diagram of the steps of a method for measuring physical property parameters of a porous medium high-temperature and high-pressure fluid according to an embodiment of the present application. As shown in FIG6 , the method for measuring physical property parameters according to an embodiment of the present invention includes the following steps:

[0116] Step S601: During pore volume calibration, inject a first experimental gas into the first type one core module A1 in the core device A;

[0117] Step S602: Control the on / off status of the pipelines between adjacent core modules by using the control device D, and continuously record the equilibrium pressure when the first experimental gas passes through each core module at different positions in sequence, thereby calibrating the pore volume of each core;

[0118] Step S603: In the constant mass expansion stage, inject the second experimental gas and the fluid sample into the core device A respectively;

[0119] Step S604: When the fluid sample saturates the first type 1 core module A1, the on / off state of the pipeline between adjacent core modules is controlled by the control device D, and the equilibrium pressure when the fluid sample diffuses to each core module at different positions is continuously recorded. In combination with the pore volume of each core, the physical properties of the formation fluid sample are obtained.

[0120] The present invention discloses a system and method for measuring the physical properties of fluids in porous media. The system and method are mainly composed of multiple full-diameter cores and short cores connected in series, and are used to simulate the process of constant mass expansion of formation fluids in a reservoir. By directly measuring the pressure of the fluid during the expansion process in the core and its corresponding volume, high-pressure physical properties such as the saturation pressure of the formation fluid are determined. As a result, the present invention can directly measure the relationship between the pressure and pore volume of the formation fluid during the expansion process in the actual reservoir porous medium, accurately obtain the high-pressure physical properties such as the saturation pressure, deviation coefficient, compression coefficient and volume coefficient of the fluid in the core, clarify the true phase characteristics of the formation fluid in the reservoir porous medium, and provide objective basic parameters for the development plan design, reserve calculation and oil and gas test of low-porosity and low-permeability oil and gas reservoirs, which has extremely wide promotion and application value.

[0121] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any changes or substitutions that can be easily conceived by anyone skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be based on the scope of protection of the claims.

[0122] In the description of the present invention, unless otherwise specified, "plurality" means two or more; terms such as "upper," "lower," "left," "right," "inner," "outer," "front end," "rear end," "head," and "tail" indicate positions or relationships based on those shown in the accompanying drawings. These terms are intended solely to facilitate the description of the present invention and simplify the description. They do not indicate or imply that the devices or components referred to must have a specific orientation, be constructed, or operate in a specific orientation. Therefore, they should not be construed as limiting the present invention. Furthermore, terms such as "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0123] In the description of the present invention, it should be noted that, unless otherwise expressly specified or limited, the terms "connected" and "connection" should be understood in a broad sense. For example, they can refer to fixed connection, detachable connection, or integral connection; mechanical connection, electrical connection; direct connection, or indirect connection through an intermediary. Those skilled in the art will understand the specific meanings of the above terms in the present invention based on the specific circumstances.

[0124] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should extend to equivalent substitutions of these features understood by those skilled in the relevant art. It should also be understood that the terminology used herein is for the purpose of describing specific embodiments only and is not intended to be limiting.

[0125] References in this specification to "one embodiment" or "an embodiment" mean that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the present invention. Therefore, appearances of the phrases "one embodiment" or "an embodiment" in various places throughout this specification do not necessarily refer to the same embodiment.

[0126] Although the embodiments disclosed above are for facilitating understanding of the present invention, the contents described are merely embodiments adopted for facilitating understanding of the present invention and are not intended to limit the present invention. Any person skilled in the art of the present invention may make any modifications and changes in the form and details of the implementation without departing from the spirit and scope of the present invention. However, the scope of patent protection of the present invention shall still be subject to the scope defined by the appended claims.

Claims

1. A system for measuring physical parameters of a fluid in a porous medium, comprising: A core device, comprising at least two first-type core modules and a second-type core module located between the at least two first-type core modules, wherein the size of the core in the first-type core module is greater than the size of the core in the second-type core module; A control device is used to control the on / off status of pipelines between adjacent core modules. The control device is further configured to calibrate the pore volume of each core according to the equilibrium pressure when the experimental gas injected into the core device passes through each core module in turn, and to record the equilibrium pressure when the fluid sample injected into the core device diffuses to each core module in turn when the fluid sample saturates the first first-type core module, thereby obtaining the physical properties of the fluid sample based on the pore volume and the equilibrium pressure.

2. The system according to claim 1, characterized in that The system also includes an injection device, wherein the injection device is configured to inject a first experimental gas into the first first-type core module during a pore volume calibration phase, and to inject a second experimental gas and a fluid sample during a constant mass expansion phase, wherein the fluid sample is used to simulate the fluid in a porous medium formation downhole.

3. The system according to claim 2, characterized in that The system also includes a temperature control device for providing a simulated formation temperature to the core device.

4. The system according to any one of claims 2 or 3, characterized in that The system further comprises a confining pressure device, which is in communication with the core sidewalls in each of the core modules.

5. The system according to any one of claims 2 to 4, characterized in that: The core modules are connected in series through high-pressure pipelines, wherein a connecting valve is provided at the end of each core module, and a pressure sensor is provided at each connecting valve, wherein the system further comprises a back pressure device hung at the outlet of the first first-type core module.

6. The system according to claim 5, characterized in that The control device is configured to: during the pore volume calibration stage: Only the connecting valve for connecting the injection device and the first core is opened, and the gas volume of the first experimental gas injected into the first core and the first value of the first equilibrium pressure are recorded. Opening the connecting valve for connecting the first core and the second core, recording the second value of the first equilibrium pressure, Open the connecting valves for connecting the core modules in sequence, and record the other values ​​of the first equilibrium pressure respectively. The pore volume of each core is obtained respectively according to the first value, the second value and other values ​​of the first equilibrium pressure.

7. The system according to claim 6, characterized in that The control device is further configured to: Only the connecting valve for connecting the injection device and the first core is opened, and the second experimental gas is injected into the first core. The back pressure device is adjusted so that the pressure of the first core is raised to a preset formation pressure. allowing the fluid sample to be injected into the first core to saturate the first core, and then closing the connecting valve for connecting the injection device and the first core, opening a connecting valve for connecting the first core and the second core, allowing the fluid sample in the first core to diffuse into the second core, and recording a first value of a second equilibrium pressure, Open the connecting valves for connecting the cores in sequence and record the other values ​​of the second equilibrium pressure. The physical property parameters of the fluid sample are calculated according to the first value and other values ​​of the second equilibrium pressure and the pore volume of each core.

8. The system according to claim 7, characterized in that The physical property parameters include saturation pressure, wherein, The control device is further configured to draw a curve representing the relationship between pressure and pore volume during the core expansion process, and obtain the saturation pressure of the fluid sample by identifying an inflection point in the curve.

9. The system according to any one of claims 5 to 8, characterized in that: The control device is further configured to: in the step of calibrating the pore volume of each core: The pore volume of each core is also subtracted from the volume of all high-pressure pipelines located in front of the corresponding core.

10. The system according to any one of claims 5 to 9, characterized in that: The control device is further configured to determine the number of the first type of core modules and the second type of core modules by: Conduct PVT phase state experiments on fluid samples to determine the dissolved gas-oil ratio of formation fluid in the PVT tube, the saturation pressure based on the PVT experiment, and the pressure-volume relationship curve; According to the PV relationship in the pressure-volume relationship curve where the pressure is greater than the saturation pressure based on the PVT experiment, the corresponding pressure drop value when the formation fluid sample increases per unit core pore volume is calculated, and based on this, the number of the second type of core samples required to reduce the actual formation pressure to the saturation pressure based on the PVT experiment is calculated; The number of the first type of core samples required to reduce the saturation pressure based on the PVT experiment to the final pressure is calculated, wherein the final pressure is the pressure corresponding to three times the initial fluid volume required to saturate the first type of core samples.

11. The system according to claim 7 or 8, characterized in that: The system also includes an oil and gas recovery device hung at the outlet of the first first-type core module, wherein the control device is also configured to obtain gas-oil ratio data from the oil and gas recovery device, and determine the timing of completing formation fluid saturation based on the changing state of the gas-oil ratio data.

12. A method for measuring the physical parameters of a fluid in a porous medium, characterized in that: The method is implemented using the system according to any one of claims 1 to 11, wherein the method comprises: injecting a first experimental gas into a first core module of the first type; The on-off state of the pipelines between adjacent core modules is controlled by the control device, and the equilibrium pressure when the first experimental gas passes through each core module in turn is continuously recorded, so as to calibrate the pore volume of each core; injecting a second experimental gas and a fluid sample into the core device respectively; When the fluid sample saturates the first type of core module, the control device is used to control the on / off state of the pipeline between adjacent core modules, and the equilibrium pressure when the fluid sample diffuses to each core module in turn is continuously recorded, and the physical properties of the fluid sample are obtained in combination with the pore volume of each core.

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