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 devi

Description

Technical Field The present invention relates to the technical field of phase state experiment of fluid in oil and gas field development, and specifically to a system and method for measuring physical property parameters of fluid in porous medium. Technical Background The physical property parameters of fluid in oil and gas reservoirs are indispensable fundamental data for determining reservoir types, reserve calculation, reservoir engineering and oil production technology research, as well as development plan formulation. Typically, the physical property parameters of fluid in oil and gas reservoirs are acquired mainly according to the experimental method specified in the National Standards of China “Analysis method for reservoir fluid physical properties” (GB / T26981-2020), for example, using a PVT cell. However, with the ongoing advancement of science and technology as well as the continuous progress in experimental techniques, device and methods, it is gradually realized that there are significant differences between high-pressure physical property characteristics of formation fluids in reservoir porous media and values measured in conventional PVT cells. The disparity between the two increases as the pore size in the reservoir porous media decreases. Further, in CN112214935A entitled “Method and system for calculating fluid phase state in porous medium”, a phase equilibrium calculation model is constructed considering capillary pressure effects, critical temperature and critical pressure shifts, and pore size distribution in porous media based on experimental results. It is proposed that when the pore size is less than 100 nm, the porous media can significantly affect the fluid phase state in the formation. Since PVT phase state experiments are conducted under high-temperature, high-pressure and spatially confined conditions, however, it is extremely difficult to determine the actual phase state characteristics of formation fluid in the core. In CN105445270A entitled “Apparatus for monitoring fluid phase behavior changes in porous medium”, an apparatus for monitoring fluid phase behavior changes in porous medium is designed. Fluid phase behavior changes at the core end faces can be visually observed through viewing windows at both ends of a core holder. However, the limitation of this apparatus is that the fluid observed through the windows is no longer in the state when it is within the porous medium of the core, but rather in the state when the fluid has entered the bulk phase space (the same as in a PVT cell). Additionally, in a prior art entitled “System and method for measuring bubble point pressure of crude oil in porous medium” (CN201910185767.9), a system and method for measuring bubble point pressure of crude oil in porous medium are designed by connecting a long core holder in series with a PVT cell. However, the problem with this method lies in that the core and the PVT cell belong to two different media, resulting in different fluid phase states therebetween. The bubble point measured through the PVT cell in series connection with the core holder is no longer the phase state characteristic of the fluid within the porous media of the core. In summary, most of current devices and methods for research of fluid phase state in porous media have certain disadvantages, which are unable to obtain directly measured parameters characterizing the true fluid state within porous media, leading to significant limitations in experimental results and failing to reflect the actual fluid phase state in the core. Summary of the Invention The present invention aims to propose a method for determining physical property parameters of fluid formation that can reflect the true phase state of fluid within a rock core. In order to solve the above technical problem, the embodiments of the present invention provide a system for measuring physical property parameters of fluid in porous medium, which comprises a core device, comprising at least two first-type core modules and a second-type core module arranged therebetween, wherein a core size of a core in the first-type core module is larger than that in the second-type core module; and a control device, configured to control an on / off state of pipelines arranged between adjacent core modules, wherein the control device is further configured to calibrate a pore volume of each core according to an equilibrium pressure when an experimental gas injected into the core device sequentially passes through each core module, and to record the equilibrium pressure when a fluid sample injected into the core device diffuses sequentially to each core module after saturating a first one of the first-type core modules, thereby obtaining the physical property parameters of the fluid sampl e based on the pore volume and the equilibrium pressure. Preferably, the system further comprises an injection device, which is configured to inject a first experimental gas to the first one of the first-type core modules in a pore volume calibration stage, and inject a second experimental gas and the fluid sample in a constant composition expansion stage, wherein the fluid sample is provided to simulate fluid in downhole porous medium formation. Preferably, the system further includes a temperature control device, which is configured to provide a simulated formation temperature to the core device. Preferably, the system further includes a confining pressure device, which is in communication with a sidewall of the core in each core module. Preferably, the core modules are connected in series via high-pressure pipelines, wherein a communication valve is arranged at each end of each core module, and a pressure sensor is arranged at each communication valve, and the system further includes a back pressure device attached to an outlet of the first one of the first-type core modules. Preferably, the control device, in the core pore volume calibration stage, is further configured to: turn on only a communication valve for communicating said injection device and a first core, and record a volume of the first experimental gas injected into the first core and a first value of a first equilibrium pressure; turn on a communication valve for communicating the first core with a second core, and record a second value of the first equilibrium pressure; turn on the communication valves for communicating each core module sequentially, and record other values of the first equilibrium pressure, respectively; and obtain the pore volume of each core separately based on said first value, said second value, and said other values of the first equilibrium pressure. Preferably, the control device, in the constant-composition expansion stage, is further configured to: turn on only the communication valve for communicating the injection device and the first core, and inject the second experimental gas into the first core; adjust the backpressure device to raise a pressure of the first core to a preset formation pressure; allow the fluid sample to be injected into the first core to saturate it, and then turn off the communication valve for communicating the injection device and the first core; turn on the communication valve for communicating the first core and the second core, allow the fluid sample in the first core to diffuse into the second core, and record a first value of the second equilibrium, pressure, turn on the communication valves for communicating each core module sequentially, and record other values of the second equilibrium pressure; and calculate the physical property parameters of the fluid sample based on said first value and said other values of the second equilibrium pressure and the pore volume of each core. Preferably, the physical property parameters include saturation pressure, wherein the control device is further configured to plot a curve characterizing a relationship between pressure and pore volume during core expansion, thereby obtaining the saturation pressure of the fluid sample by identifying an inflection point in the curve. Preferably, the control device, when calibrating the pore volume of each core, is further configured to subtract a volume of all high-pressure pipelines located before said core from the pore volume of each core. Preferably, the control device is further configured to determine numbers of the first-type core modules and the second-type core modules according to steps of performing a PVT phase state experiment on the fluid sample to measure a solution gas-oil ratio of the formation fluid in a PVT cell, a PVT experiment-based saturation pressure, and a PV relationship curve; calculating a pressure drop value corresponding to each increase in the volume of the formation fluid sample equal to the pore volume of the core based on a PV relationship in the PV relationship curve where the pressure is greater than the PVT experiment-based saturation pressure, and further calculating a number of the second-type core samples required for a pressure drop from an actual formation pressure to the PVT experiment-based saturation pressure; and calculating a number of the first-type core samples required for a pressure drop from the PVT experiment-based saturation pressure to a final pressure, wherein said final pressure is a pressure when a volume of the injected fluid sample reaches three times an initial fluid volume required to saturate the first-type core sample. Preferably, the system further comprises an oil-gas recovery device attached to an outlet of the first one of the first-type core modules, wherein the control device is further configured to obtain gas-oil ratio data from the oil-gas recovery device and determine a timing for completing formation fluid saturation based on changes in the gas-oil ratio data. According to another aspect of the present invention, a method for measuring physical property parameters of fluid in porous medium with the above system is provided, comprising steps of: injecting the first experimental gas into the first one of the first-type core modules; controlling the turning on / off state of pipelines between adjacent core modules via the control device, and continuously recording the equilibrium pressures when the first experimental gas passes through each core module in sequence, thereby calibrating the pore volume of each core; injecting the second experimental gas and the fluid sample into the core device respectively; and controlling the turning on / off state of pipelines between adjacent core modules via the control device after the fluid sample saturates the first one of the first-type core modules, and continuously recording the equilibrium pressures when the fluid sample diffuses to each core module in sequence, in order to obtain the physical property parameters of the fluid sample based on the pore volume of each core. Compared with the prior arts, one or more of the embodiments in the above technical solutions may have the following advantages or beneficial effects. The present invention proposes a system and method for measuring physical property parameters of fluid in porous medium. The system mainly employs a plurality of full-diameter and short core modules connected in sequence to simulate constant-composition expansion of formation fluid within a reservoir. By directly measuring the pressure and the corresponding volume during fluid expansion inside the core, high-pressure physical parameters such as saturation pressure of the formation fluid are determined. Therefore, the present invention can directly measure the relationship between pressure and pore volume during the expansion of formation fluid within actual porous media of the reservoir, and accurately obtain high-pressure physical parameters including saturation pressure, deviation factor, compressibility, and volume factor of the fluid in the core, thereby determining the actual phase state characteristics of the formation fluid within the porous media of the reservoir. Therefore, the present invention can provide objective basic parameters for the development planning, reserve calculation, and well testing / production for low-porosity and low-permeability oil and gas reservoirs, demonstrating significant potential for application and popularization. Other features and advantages of the present invention will be set forth in the description which follows, and, in part, will be apparent from the description, or may be learned from the implementation of the present invention. The objective and other advantages of the present invention may be realized and attained from the structure particularly pointed out in the description, claims and drawings. Brief Description of the Drawings The accompanying drawings are used to provide a further understanding on the present invention, and constitute a part of the description. Together with the embodiments of the present invention, the drawings are intended to explain the present invention, but do not constitute any limitation to the present invention. In the drawings: Fig. 1 schematically shows an overall structure of a system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention; Fig. 2 schematically shows a detailed structure of the system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention; Fig. 3 is a flow chart schematically showing a procedure for measuring physical property parameters of fluid in porous medium with the system according to embodiments of the present invention; Fig. 4 schematically shows a comparison between PV relationship curves measured by the system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention and by a conventional PVT cell; Fig. 5 schematically shows a comparison between inflection points in the PV relationship curves measured by the system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention and by a conventional PVT cell; and Fig. 6 schematically shows steps of a method for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention. Detailed Description of Embodiments The implementation mode of the present invention will be explained in detail with reference to the embodiments and the accompanying drawings, whereby it can be fully understood how to solve the technical problem by the technical means according to the present invention, implement the technical solution, and achieve the technical effects thereof. All the embodiments and the technical features defined therein may be combined together if there is no conflict, and the technical solutions obtained in this manner all fall within the scope of protection of the present invention. In addition, the steps illustrated in the flow chart in the drawings can be performed in a computer system containing a set of computer-executable instructions. Moreover, although a logical sequence is shown in the flow chart, in some cases these steps as shown or described may be performed in an order different than that shown herein. The terms used herein are only intended to describe detailed embodiments, rather than intended to limit exemplary embodiments. Unless otherwise specifically indicated in the context, the singular forms “a”, “an” and “the” as used herein also include the plural. It should also be understood that the terms “including” and / or “comprising” as used herein specify the stated feature, integer, step, operation, unit, and / or component, and do not exclude the presence of, or the addition of, one or more other features, integers, steps, operations, units, components, and / or combinations thereof. In order to solve one or more of the technical problems in the prior arts, the present invention provides a system and method for measuring physical property parameters of fluid in porous medium. This system and method can accurately obtain the actual high-pressure physical property parameters of fluid in porous media of reservoir, in order to determine the actual phase state characteristics of fluid in the formation, thereby providing accurate data support for determining reservoir types, reserve calculation, and reservoir development planning. Fig. 1 schematically shows an overall structure of the system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention. As shown in Fig. 1, the system for measuring physical property parameters of fluid in porous medium (also referred to as the “physical property parameter measuring system”) described in the embodiments of the present invention comprises a core device A, an injection device B, a confining pressure device C, and a control device D. The core device A comprises at least two first-type core modules Al, and a second-type core module A2 arranged between the at least two first-type core modules. In the embodiments of the present invention, one or more of the second-type core module A2 may be provided. When multiple second-type core modules A2 are provided, they are connected in series. The first-type core module Al contains a first-type core 2, and the second-type core module A2 contains a second-type core 4 (see Fig. 2). In the embodiments of the present invention, the core modules are connected in series via high-pressure pipelines. First, several second-type core modules A2 are connected in series via high-pressure pipelines to form a second-type core module sequence. Then, at least two first-type core modules Al are respectively arranged at two end faces of the second-type core module sequence. That is, one first-type core module Al is arranged at an inlet end face of the second-type core module sequence, and the remaining first-type core modules Al are arranged at an outlet end face thereof. Similarly, the first-type core modules Al are connected in series with the adjacent second-type core modules A2 via high-pressure pipelines. In the embodiments of the present invention, end faces of cores within adjacent core modules are arranged opposite each other. In the embodiments of the present invention, a core size of the first-type core module AI is larger than that of the second-type core module A2. The core size includes core diameter and core length. Specifically, a core diameter of the first-type core module Al is larger than that of the second-type core module A2, and a core length of the first-type core module A1 is larger than that of the second-type core module A2. The injection device B is connected to an inlet end of the first one of the first-type core modules Al within the core device A via a high-pressure inlet pipeline 22, as shown in Fig. 2. Additionally, as shown in this drawing, a high-pressure output pipeline 29 is arranged at an outlet end of the last first-type core module Al within the core device A. The injection device B is configured to inject experimental gases and fluid samples required for the experiment. Specifically, the injection device B is configured to inject a first experimental gas in a pore volume calibration stage, and a second experimental gas and a formation fluid sample in a constant composition expansion experiment stage. In the embodiments of the present invention, the core device A is configured to simulate the porous medium environment of the downhole formation. The fluid sample (also referred to as the “formation fluid sample”) is configured to simulate the fluid within the downhole porous medium formation, thereby simulating the physical property characteristics of the fluid under high-temperature and high-pressure conditions in porous medium. The confining pressure device C is connected to core sidewalls in core modules Al, A2 of the core device A, and configured to provide simulated confining pressure to each core module AI, A2 in the core device A, thereby simulating the compressive state of the sample core under actual overburden rock pressure in the formation. The control device D is configured to control an on / off state of the pipelines between adjacent core modules Al, A2. That is, the control device D controls the on / off state of the high-pressure pipelines (including high-pressure series pipelines, high-pressure inlet pipeline, and high-pressure outlet pipeline) at end faces of each core module Al, A2. By controlling the on / off state of the pipelines between adjacent core modules Al, A2, the control device D continuously records an equilibrium pressure (recorded as a first equilibrium pressure) when the first experimental gas sequentially passes through each core module Al, A2 in different positions, thereby calibrating the pore volume of each core. Additionally, while controlling the saturation of the formation fluid sample injected into the core device A in the first one of the first-type core modules Al, the control device D continuously records an equilibrium pressure (recorded as a second equilibrium pressure) when the formation fluid sample sequentially diffuses into each core module Al, A2 in different positions by controlling the on / off state of the pipelines between adjacent core modules Al, A2. On this basis, in combination with the pore volume of each core, the physical property parameters of the form ation fluid sample are ul tim ately obtained. Thus, the accurate measurement of the pressure and the corresponding pore volume during the constant composition expansion of the high-pressure fluid sample within the core can be achieved by the present invention. Fig. 2 schematically shows a detailed structure of the system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention. The detailed structure will be explained below with reference to Fig. 2. As shown in Fig 2, the first-type core module Al includes the first-type core 2, core holders 1, 10 (full-diameter core holders), and a core sleeve 6. In one embodiment, a size range of the first-type core is the core diameter of 8-10 cm and the core length of 3-15 cm. The second-type core module A2 includes the second-type core 4, core holders 3, 5, 7, 8, 9 (short core holders), and a core sleeve 6. In one embodiment, a size range of the second-type core is the core diameter of 1.8-3.8 cm and the core length of 1-15 cm. The structures of the full-diameter core holder, the short core holder and the core sleeve, as well as the clamping mode of the core in the core holders, are known to one skilled in the art and will not be described in detail here. Corresponding communication valves 11, 13, 15, 16, 17... are arranged at an end 18 of each core module Al, A2. Specifically, corresponding communication valves are arranged on each high-pressure series pipeline, high-pressure inlet pipeline, and high-pressure outlet pipeline to connect the core modules in series. In the embodiments of the present invention, the communication valves on each high-pressure series pipeline, high-pressure inlet pipeline, and high-pressure outlet pipeline are three-way valves. The full-diameter core holders 1, 10 are used to hold the full-diameter core 2. The first-type core 2 is wrapped in a flexible sleeve (rubber sleeve or high-pressure heat shrink sleeve) 6, exposing only the two end faces of the core. The lull-diameter core 2 in the full-diameter core holder 1 is first used to saturate high-pressure formation fluid, and then the fluid in the full-diameter core 2 is expanded and diffused into the cores in the other holders. The full-diameter core 2 is chosen as the first core because the full-diameter core has a large pore volume and can saturate a large amount of formation fluid, facilitating the subsequent expansion. After fully saturated with formation fluid, the full-diameter core 2 in the full-diameter core holder 1 is connected to the communication valve 13 via a 1 / 16-inch high-pressure series pipeline 12, and then connected to the short core holder 3. The short core holders 3, 5, 7, 8, 9 are used to hold the short core 4. The second-type core 4 is also wrapped in the flexible sleeve (rubber sleeve or high-pressure heat shrink sleeve) 6, exposing only the two end faces of the core. The short core holders 3, 5, 7, 8, 9 are connected in series sequentially to the communication valve 13 via the 1 / 16-inch high-pressure pipeline 12. It should be noted that the number of the first-type core modules Al and the second-type core modules A2 is not limited in the present invention. One skilled in the art can adjust the numbers of full-diameter cores and short cores according to the experimental pressures (formation pressure and saturation pressure) and the required expansion volume. In the embodiment of the present invention, the high-pressure series pipeline 12 is preferably a 1 / 16-inch high-pressure pipeline. This type of pipeline is required to be as short as possible, preferably with a length of 3-5 cm, in order to ensure a minimized volume within the pipeline. Referring to Fig. 2, the injection device B comprises a dual-cylinder piston pump assembly 19 and a piston container 21. The two piston pumps of the dual-cylinder piston pump assembly 19 are respectively in communication with two storage chambers within the piston container 21 via corresponding two-way valves 20. The dual-cylinder piston pump assembly 19 is configured to transmit pressure to the piston container via a pressure medium. The piston container 21 is configured to inject, by means of the transmitted pressure, the first experimental gas required during the pore volume calibration stage into the first one of the first-type core modules Al, and the second experimental gas and the formation fluid sample during the constant composition expansion stage. The first experimental gas is preferably helium. The second experimental gas is preferably natural gas. Specifically, the dual-cylinder piston pump assembly 19 is configured to provide displacement power to the piston container 21. With distilled water as the pressure medium, the pressure from the dual-cylinder piston pump assembly 19 is transmitted to the piston container 21, so that the piston can push the first experimental gas, the second experimental gas, or the formation fluid sample into the full-diameter core holder 1. The confining pressure device C is in communication with the core sidewalls within the core modules Al, A2. The confining pressure device C may include a dual-cylinder piston pump 28. Specifically, the dual-cylinder piston pump 28 of the confining pressure device C is in communication with each core module Al, A2 via high-pressure injection pipelines 22 connected to the respective core sidewalls, so that pressure can be applied via the dual-cylinder piston pump 28 to the flexible sleeve 6 wrapping the cores to simulate the compression of overburden rock pressure on the core, wherein the pressure medium is distilled water. Additionally, said core sleeve 6 is a heating sleeve. Therefore, the physical property parameter measuring system described in the embodiments of the present invention further includes a temperature control device 27, which is configured to provide simulated formation temperature to each core module Al, A2 in the core device A. In one embodiment, the temperature control device is a temperature control box 27. Specifically, the core holder is wTapped with the heating sleeve 6. The temperature control box 27 controls the temperature of the heating sleeve, thereby controlling and regulating the core temperature, so that the temperature of each core is consistent with the actual formation temperature. Further, the physical property parameter measuring system described in the embodiments of the present invention further includes a back pressure device (not labelled) attached to an outlet of the first one of the first-type core modules AI. The back pressure device comprises a back pressure pump 23 and a back pressure valve 25. The back pressure pump may be a single-cylinder piston pump 23. Specifically, the single-cylinder piston pump 23 is configured to provide pressure to the back pressure valve 25. By controlling the back pressure valve 25, the pressure at the outlet end of the full-diameter core holder 1 can be adjusted. In the embodiments of the present invention, a two-way valve 14 is arranged at a front end of the back pressure valve 25. The two-way valve 14 is configured to control the communication between the back pressure device and the first one of the first-type core modules Al. Specifically, the two-way valve 14 arranged at the front end of the back pressure valve 25 is controlled by the control device D, which, on this basis, further controls the switching between the full-diameter core 2 and the three-way valve 13 after the full-diameter core 2 is saturated by the formation fluid. When the two-way valve 14 is turned on, the full-diameter core 2 will be saturated. After the saturation is completed, the two-way valve 14 should be turned off. Further, the physical property parameter measuring system described in the embodiments of the present invention further includes an oil-gas recovery device (not labelled) attached to the outlet of the first one of the first-type core modules Al. The oil-gas recovery device is attached to a rear end of the back pressure valve 25 within the back pressure device, and comprises an oil-gas separation bottle 24 and a gas meter 26. Additionally, a pressure sensor 18 for measuring equilibrium pressure is arranged at each communication valve at the end faces of each core module Al, A2, forming a pressure monitoring group. The pressure monitoring group (including pressure sensors connected to three-way valves 11, 13, 15, 16, etc.) is configured to measure the pressures 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. in the corresponding positions. For example, in the embodiments of the present invention, the three-way valve 11 only controls the communication of the two (pipeline) communication ports of the valve, but does not control its communication with the pressure sensor 18. That is, the pressure sensor 18 is always in communication with one of the pipeline communication ports of the three-way valve 11, and is in communication with the other pipeline communication port thereof after the valve is turned on. In this manner, the volume of communication pipeline between the core holders can be reduced, thus ensuring the accuracy of experimental results. Fig. 3 is a flow chart schematically showing implementation of the system for measuring physical property parameters of fluid in porous medium according to embodiments of the present invention. With reference to Fig. 3, the implementation procedure of the physical property parameter measuring system described in the embodiments of the present invention will be explained in detail as follows. Before the system setup (before the start of the experiment), the numbers of the first-type core modules and the second-type core modules Al, A2 are determined by the control device D. The numbers of the first-type core modules and the second-type core modules is determined by the control device D according to the following steps. Specifically, first, a PVT phase state experiment is performed on the formation fluid sample to measure a solution gas-oil ratio of the formation fluid in a PVT cell, a saturation pressure based on the PVT experiment, and a pressure-volume relationship curve. Also, the porosity and the permeability of the first-type core samples and the second-type core samples are measured through the core analysis method. Then, based on the pressure-volume (PV) relationship in the PV relationship curve where the pressure is greater than the PVT experiment-based saturation pressure, the pressure drop value of the formation fluid sample corresponding to the increase in core pore volume per unit is calculated. Based on the pressure drop value corresponding to the core pore volume, the number of the second-type core samples required for a pressure drop from the actual formation pressure to the PVT experiment-based saturation pressure is calculated. Finally, the number of the first-type core samples required for a pressure drop from the PVT experiment-based saturation pressure to a final pressure is calculated, wherein said final pressure is a pressure when the volume of the injected fluid sample reaches three times the initial fluid volume required to saturate the first-type core sample. Specifically, before the start of the experiment, it is necessary to perform a PVT phase state experiment on the measured formation fluid sample according to the National Standards of China “Analysis method for reservoir fluid physical properties” (GB / T26981-2020), in order to determine parameters such as the solution gas-oil ratio, the saturation pressure, and the PV relationship curve of the formation fluid in a PVT cell. Additionally, it is necessary to determine the porosity and permeability of several core samples such as the required full-diameter core 2 and the short core 4 according to the National Standards of China “Practices for core analysis” (GB / T 29172-2012). Then, based on the saturation pressure measured by the PVT experiment, the formation-saturation pressure difference (i.e., the difference between the formation pressure and the saturation pressure) is calculated. In combination with the PV relationship in the PV relationship curve of the formati on fluid sample where pressure is greater than the saturation pressure, the pressure drop corresponding to each increase in the volume of the formation fluid sample, which is equal to the pore volume of a core, is calculated. In combination with the porosity and permeability of the short core 4, the number of short cores required for a pressure drop from the original formation pressure to the PVT experiment-based saturation pressure is further calculated. Furthermore, based on the porosity and permeability of the full-diameter core 2, the number of first-type core samples required for a further pressure drop from the saturation pressure to the final pressure (i.e., the pressure when the volume is 3 times the initial fluid volume) in the PV curve is calculated. It should be noted that when the pressure is greater than the saturation pressure, short cores with as small a pore volume as possible can be selected to avoid rapid pressure drop due to an overly large pore volume, which would skip over the saturation pressure. When the pressure is less than the saturation pressure, long cores or full-diameter cores with large pore volumes can be selected to achieve rapid pressure drop to the final pressure. Therefore, the embodiments of the present invention conduct fluid saturation pressure measuring experiment using a core device including at least two first-type core modules and several core modules located therebetween, thus effectively controlling the rate of pressure change and improving the accuracy of the final measurement results. Then, the control device D continues io conduct the experiment of calibrating the pore volume of each core under the confining pressure. In one embodiment, the control device D, in the core pore volume calibration stage, is further configured to: turn on only the communication valve 11 for communicating said injection device and the first core, inject the first experimental gas from the inlet of the core device A, and record the volume of the first experimental gas injected into the first core and a first value of the first equilibrium pressure; turn on the communication valve 13 for communicating the first core with the second core, and record a second value of the first equilibrium pressure; turn on the communication valves 15, 16, etc., for communicating each core module Al, A2 sequentially, and record other values of the first equilibrium pressure, respectively; and obtain the pore volume of each core separately based on the first value, the second value, and other values of the first equilibrium pressure. Specifically, the control device D conducts the experiment of calibrating the pore volume of each core according to steps of: controlling the confining pressure device C to apply confining pressure to each core module Al, A2; turning on the communication valves located at the end faces of each core module Al, A2 to evacuate all cores; turning off the communication valves for connecting the core modules Al, A2 in series; controlling the injection device B to inject the first experimental gas from the inlet of the core device A, and record the gas volume injected into the first core and the first equilibrium pressure after the pressure stabilizes; turning on the communication valve for communicating the first core with the second core, and record the current first equilibrium pressure after the pressure stabilizes; turning on, in a similar manner, sequentially the communication valves for connecting the core modules in series, and record the first equilibrium pressure after the pressure stabilizes respectively; and obtain the pore volume of each core separately based on the first equilibrium pressures recorded in different periods. Specifically, in Step SI, the control device D turns on all valves controlling the confining pressure of the core holders, allows the pressure generated by the dual-cylinder piston pump 28 to be transmitted to each core holder, thus applying the confining pressure equivalent to the overburden rock pressure. In Step S2, the control device D turns on all valves 11, 13, 15, 16, etc., located at the end faces of each core module. In Step S3, the control device D controls the evacuation of all cores from the three-way valves 11 and 17 at the same time, until the control device D detects that the readings of the pressure sensors corresponding to all the cores are consistent. In Step S4, the control device D turns off all valves 13, 15, 16, etc., for connecting the core holders in series, thereby disconnecting the cores within each core holder. In Step S5, under the control of the control device D, the injection device B injects helium gas at constant pressure from the three-way valve 11 into the full-diameter core 2. The control device D records the volume Vi of helium gas injected into the full-diameter core 2 at constant pressure and the pressure Pi in the full-diameter core 2 (the pressure at the valve 11) after the pressure at the valve 11 stabilizes. In Step S6, the control device D then turns on the three-way valve 13 until the pressures inside the core holders 1 and 3 stabilize (i.e., the pressure at the front ends of the first and second cores) and remain consistent. At this point, the control device D records the current equilibrium pressure as P2, and calculates the pore volume V2 of the short core 4 with an equation V2==Z2 * Pi sVi / (Zi *P2)-Vi (which is derived from PV===ZnRT, wherein Zt and Z2 denote deviation factors of helium gas under Pj and P2, respectively, which can be obtained from a lookup table). Next, in Step S7, the three-way valve 15 is turned on, and the aforementioned step S6 is repeated, in order to calculate the pore volume of the core inside the core holder 5. The calibration experiment stops until the pore volumes of all cores are calculated. Next, under the control of the control device D, the saturated formation fluid experiment and the fluid physical property parameter measuring experiment on the full-diameter core 2 are conducted under the confining pressure. In one embodiment, during the constant-composition expansion stage, the control device D is further configured to: turn on only the communication valve 11 for communicating the injection device B and the first core, and inject the second experimental gas from the inlet of the core device A into the first core; adjust the backpressure device to raise the pressure of the first core to the preset formation pressure; allow the fluid sample to be injected from the inlet of the core device A into the first core to saturate it, and then turn off the communication valve 11 communicating the injection device B and the first core; turn on the communication valve 13 for communicating the first core and the second core to allow the fluid sample in the first core to diffuse into the second core, and record a first value of the current second equilibrium pressure; turn on the communication valves 15, 16, etc., for communicating each core module sequentially, and record other values of the second equilibrium pressure separately; and calculate the physical property parameters of the fluid sample based on the first value and other values of the second equilibrium pressure and the pore volume of each core. Specifically, the control device D conducts the constant-composition expansion experiment according to steps of: turning on the communication valves located at the end faces of each core module Al, A2, thereby evacuating all cores; turning off the communication valves for connecting the core modules Al, A2 in series; controlling the injection device B to inject the second experimental gas from the inlet of the core device A, and adjusting the backpressure device to raise the pressure of the first core to the preset formation pressure; controlling the injection device B to inject the formation fluid sample from the inlet of the core device A to displace the first core and complete the saturation of the formation fluid; turning off the valve at the inlet of the core device A; turning on the communication valve for communicating 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; turning on, in a similar manner, the communication valves for connecting the core modules Al, A2 in series sequentially, and recording the second equilibrium pressures after the pressure stabilizes, respectively; and calculating the high-pressure physical property parameters of the formation fluid sample based on the second equilibrium pressures recorded during different periods and the pore volume of each core. In one embodiment, the physical property parameters include the saturation pressure. Specifically, during the calculation of the saturation pressure, the control device is further configured to plot a curve characterizing the relationship between pressure and pore volume during the core expansion based on the second equilibrium pressures recorded during different periods and the pore volume of each core, thereby obtaining the saturation pressure of the formation fluid sample by identifying the inflection point in the current curve characterizing the relationship between pressure and pore volume. Specifically, in Step Ml, the control device D re-evacuates all cores connected in series, following the evacuation method described in Steps SI-S3 above. In Step M2, the control device D turns off all valves 13, 15, 16, etc., for connecting the core holders in series, thereby disconnecting the cores within the core holders. In Step M3, the control device D turns on the three-way valve 11 and the two-way valve 14. Then, the dual-cylinder piston pump assembly 19 injects natural gas into the full-diameter core 2 to fully saturate it with natural gas. Meanwhile, the single-cylinder piston pump 23 is adjusted by controlling the backpressure valve 25, in order to raise the pressure of the core 2 (based on the pressure at the valve 11) to the formation pressure. In Step M4, under the control of the control device D, the injection device B injects the formation fluid sample from the three-way valve 11 into the full-diameter core 2, allowing the formation fluid to displace the natural gas and completing the saturation of the formation fluid. In one embodiment, the control device D is further configured to obtain gas-oil ratio data from the oil-gas recovery device and determine the timing for completing the formation fluid saturation based on changes in the current gas-oil ratio data. Specifically, when the produced gas-oil ratio measured by the oil-gas separating bottle 24 and the gas meter 26 remains constant, it is determined that the formation fluid saturation is currently completed. Next, in Step M5, after the full-diameter core 2 is saturated with formation fluid, the control device D turns off the three-way valve 11 and the two-way valve 14. In Step M6, the control device D turns on the three-way valve 13, allowing the formation fluid sample in the full-diameter core 2 to diffuse into the short core 4. When the pressures at the ports of the full-diameter core 2 and the short core 4 are consistent, i.e., when the reading of the pressure sensor at the valve 11 matches those at the valves 13 and 15 (at this time, the three-way valve 15 is turned off, but the pipeline communication port communicating the pressure sensor remains in communication with the one-way pipeline communication port communicating the core holder 3, indicating that although the valve 15 is turned off, the pressure sensor thereof can still measure the pressure at the outlet of the core holder 3), the control device D records the pressure at this time as the second equilibrium pressure. In Step M7, the control device D then turns on the three-way valve 15, allowing the formation fluid sample to diffuse further into the core in core holder 5. When the port pressures of the full-diameter core 2, the short core 4, and the second short core are the same, i.e., when the readings of the pressure sensors at the valves 11, 13, 15, and 16 respectively are the same, the control device D records the pressure at this time as the second equilibrium pressure. In Step M8, Step M7 is repeated, allowing the formation fluid sample to diffuse into a next core. The control device D records the corresponding second equilibrium pressure, until the formation fluid sample enters the last full-diameter core and the recording of the second equilibrium pressure is completed, at which point the current constant-composition expansion experiment ends. In Step M9, based on the (second) equilibrium pressures of the formation fluid expanding within each core and the corresponding core pore volumes obtained in Steps M6-M8, the relationship between pressure and pore volume during the expansion of the formation fluid within the core is determined. With the inflection point of the current pressure-pore volume curve, the saturation pressure of the current formation fluid sample in the cores is determined. Additionally, according to the present invention, other reasonable parameters of the formation fluid sample in the cores can be also calculated, such as deviation coefficient, compressibility coefficient, volume coefficient and the like, with the calculation methods according to the National Standards of China “Practices for core analysis” (GB / T 29172-2012). Further, the previously calibrated pore volume of each core includes the volume of fluid in the 1 / 16-inch high-pressure series pipeline 12. Although the internal volume of the 1 / 16-inch high-pressure pipeline is very small, it can still affect the measurement results. Therefore, in the step of calibrating the pore volume of each core in the embodiments of the present invention, the control device D is also configured to subtract the (total) volume of all high-pressure pipelines located before the corresponding core from the pore volume of each core during the calibration. That is, it is necessary to eliminate the influence of the volume of the high-pressure pipelines on the measurement results. Specifically, in the above Step M9, when the formation fluid sample enters the nth core, the actual fluid volume in this core should be the total pore volume of n cores (as calibrated by helium) minus the volume of n-1 high-pressure pipelines (the volume of each pipeline can be calculated by measuring the length thereof). Thus, through the procedure implemented by the above physical property parameter measuring system, the embodiments of the present invention, based on the specific core distribution structure (arranging long cores at both ends of multiple short cores in series), can not only accurately measure the permeability of core modules of different sizes, but also conduct constant-composition expansion experiments based on the pore permeability (pore volume) of each level of core measured by this specific core distribution structure, in order to obtain more accurate fluid physical property parameters under controllable pressure change (depressurization) rates during fluid diffusion. The following example illustrates the application of the aforementioned physical property parameter measuring system of the present invention in a specific oilfield. An average permeability of a certain oil field reservoir is approximately O.IlxlO'3 pm2, with an average porosity of 6.8%, indicating the reservoir is a tight sandstone reservoir. The formation fluid is a condensate gas, with a formation temperature of 110°C and a formation pressure of 32 MPa. The phase state characteristics of the condensate gas in the reservoir differ from the measurement results in the PVT cell. Therefore, further measurement of the dew point pressure of the condensate gas in the reservoir is required. (1) Before the experiment starts, a PVT phase state experiment is conducted on the condensate gas sample according to the National Standards of China “Analysis method for reservoir fluid physical properties” (GB / T26981-2020), obtaining a dew point pressure of 26.36 MPa, a dissolved gas-oil ratio of 3934 mJ / m3, and a PV relationship curve. Additionally, the porosity and the permeability of several core samples, including full-diameter cores and short cores, are also measured according to the National Standards of China “Practices for core analysis” (GB / T 29172-2012). (2) The required number of core samples is calculated. Based on the dew point pressure, the ground-dew point pressure difference is calculated as 5.7 MPa. According to the PV relationship in the PV curve, 11 cores meeting the requirement of pore volume are selected, including 3 full-diameter cores and 8 short cores. Specific core parameters are shown in lab Ie 1. Table 1 Core Parameters No. Porosity Length (cm) Diameter (cm) Pore volume (cm3) Pore volume calibrated with helium (cm3) Core cumulative corrected pore volume (minus pipeline dead volume) (cm3) Core pressure (MPa) 1 0.076 11 10 69.56 65.63 65.63 32.231 2 0.068 3.7 1.8 0.68 0.64 66.27 29.776 3 0.059 1.6 1.8 0.25 0.24 66.51 28.898 4 0.063 1.5 1.8 0.25 0.24 66.75 28.208 5 0.057 2 1.8 0.31 0.29 67.04 27.859 6 0.066 4.2 1.8 0.75 0.71 67.74 27.070 7 0.061 4.8 1.8 0.79 0.74 68.49 26.283 8 0.058 7.9 2.5 2.38 2.25 70.73 24.283 9 0.073 8.4 3.8 7.37 6.95 77.68 20.264 10 0.065 4.6 10 24.88 23.47 101.16 14.153 11 0.073 13 10 78.97 74.50 175.65 8.050 5 (3) The pore volume of the core in each core holder under the confining pressure is calibrated. First, all valves controlling the confining pressure of the core holders are turned on to allow the pressure generated by the dual-cylinder piston pump 28 to be transferred to each core holder, applying the confining pressure up to the overburden rock pressure of the formation. Also, all valves 13, 15, 16, etc., of the core holders 10 connected in series are turned on. All the cores are evacuated from the three-way valves 11 and 17 at the same time, until the readings of the pressure sensors corresponding to all cores remain consistent. Then, all valves 13, 15, 16, etc., of the core holders connected in series are turned off to disconnect the cores within all core holders. From the three-way valve 11, helium is injected into the full-diameter core 2 15 at a constant pressure of 5 MPa, and the volume of helium V] entering the core 2 at a constant pressure is recorded. When the pressure stabilizes, the pressure Pi within the core 2 is recorded. Then, the three-way valve 13 is turned on until the pressures in core holders 1 and 3 stabilize and become consistent, and the current equilibrium pressure is record as P2. The pore volume V2 of the short core 4 is calculated with the equation V2=Z2*Pi*Vi / (Zi*P2)-Vi. Next, the three-way valve 15 is turned on, and the aforementioned steps are repeated to calculate the pore volume of the core within the core holder 5. After the pore volumes of all cores are calculated, the calibration experiment stops. The calibrated pore volumes of the cores under the confining pressure are shown in Table 1. (4) The full-diameter core 2 is saturated with formation fluid. First, all cores connected in series are re-evacuated following the method described in Step (3). Then, the valves of all cores connected in series are turned off. The three-way valve 11 and the two-way valve 14 are turned on, and the full-diameter core (core No. 1 in Table 1) is fully saturated with natural gas by means of the dual-cylinder piston pump assembly 19. The backpressure valve 25 is adjusted using the single-cylinder piston pump 23 to raise the core pressure to the formation pressure of 32 MPa. Then, the natural gas is displaced with condensate gas to complete the saturation of condensate gas. The saturation of condensate gas is considered completed when the produced gas-oil ratio measured by the oil-gas separation bottle 24 and the gas meter 26 remains constant. (5) The dew point pressure of the condensate gas in the cores is measured. After the full-diameter core (core No. 1 in Table 1) is saturated with condensate gas, the three-way valve 11 and the two-way valve 14 are turned off. The three-way valve 13 is turned on to allow the condensate gas in the full-diameter core (core No. 1 in Table 1) to diffuse into the short core (core No. 2 in Table 1). When the reading of the pressure sensor at the valve 11 is consistent with those at the valves 13 and 15, the pressure at this point is recorded. Then, the three-way valve 15 is turned on to allow the condensate gas to diffuse further into core No. 3. When the readings of the pressure sensor at the valves 11, 13, 15, and 16 are consistent, the pressure is recorded. The above steps are repeated to allow the condensate gas to diffuse into a next core. When the condensate gas enters the final full-diameter core (core No. 11 in Table 1), the experiment stops. Experimental Results Table 1 shows the relationship between core pressure and corresponding cumulative pore volume of the core (including corrected volume after subtracting dead volume in pipelines) during the constant-composition expansion of condensate gas. The PV relationship curve measured in the core as shown in Fig. 4 can be obtained by plotting the core pressure and the cumulative corrected pore volume in the same coordinate system. Another curve represents the PV relationship measured in the PVT cell, as a comparative reference. To determine the inflection points of the two different curves in Fig. 4, the curves are enlarged to obtain Fig. 5(a) and Fig. 5(b). Fig. 5(a) shows an inflection point in the enlarged PV relationship curve measured in the PVT cell, where the pressure corresponding to the inflection point is the dew point pressure measured in the PVT cell, i.e., 26.36 MPa. Fig. 5(b) shows an inflection point in the enlarged PVT relationship curve measured in the core, where the pressure corresponding to the inflection point is the dew point pressure measured in the core, i.e., 28.23 MPa. Comparing the two dew point pressures, it is found that the dew point pressure of the condensate gas measured in the core is higher than that measured in the PVT cell. This indicates that the presence of porous media can increase the dew point pressure of condensate gas, with an increase of 7.1%. Further, based on the aforementioned physical property parameter measuring system, the embodiments of the present invention also provide a method for measuring physical property parameters of fluid in porous medium (also referred to as the “physical property parameter measuring method”), which is implemented using the physical property parameter measuring system described above. Fig. 6 schematically shows steps of the method for measuring physical property parameters of high-temperature and high-pressure fluid in porous medium according to embodiments of the present invention. As shown in Fig. 6, the physical property parameter measuring method in the embodiment of the present invention comprises the following steps. Step S601: injecting the first experimental gas into the first one of the first-type core modules Al within the core device A during pore volume calibration; Step S602: controlling the turning on / off state of pipelines between adjacent core modules via the control device D, and continuously recording the equilibrium pressures when the first experimental gas passes through each core module in different positions in sequence, thereby calibrating the pore volume of each core; Step S603: injecting the second experimental gas and the fluid sample into the core device A respectively during the constant-composition expansion phase; and Step S604: controlling the turning on / off state of pipelines between adjacent core modules via the control device D when the fluid sample saturates the first one of the first-type core modules Al, and continuously recording the equilibrium pressures when the fluid sample diffuses to each core module in different positions in sequence, in order to obtain the physical property parameters of the formation fluid sample in combination with the pore volume of each core. The present invention proposes a system and method for measuring physical property parameters of fluid in porous medium. The system mainly employs a plurality of full-diameter and short core modules connected in sequence to simulate constant-composition expansion of formation fluid within a reservoir. By directly measuring the pressure and the corresponding volume during fluid expansion inside the core, high-pressure physical parameters such as saturation pressure of the formation fluid are determined. Therefore, the present invention can directly measure the relationship between pressure and pore volume during the expansion of formation fluid within actual porous media of the reservoir, and accurately obtain high-pressure physical parameters including saturation pressure, deviation factor, compressibility, and volume factor of the fluid in the core, thereby determining the actual phase state characteristics of the formation fluid within the porous media of the reservoir. Therefore, the present invention can provide objective basic parameters for the development planning, reserve calculation, and well testing / production for low-porosity and low-permeability oil and gas reservoirs, demonstrating significant potential for application and popularization. The foregoing is merely illustrative of preferred embodiments of the present invention, but the scope of protection of the present invention is not limited thereto. Any modifications or substitutions that can be readily conceived by one skilled in the art within the technical scope disclosed herein shall fall within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined according to the scope of protection of the claims. In the description of the present invention, “a plurality of means two or more, unless otherwise specified. It should be understood that the terms “upper”, “lower”, “left”, “right”, “internal”, “external”, “front end”, “rear end”, “head portion”, “tail portion”, and the like indicate orientations or positions based on those shown in the drawings, which are used only for simplified and illustrative purposes of the present invention, and are not intended to indicate or imply a particular orientation, or the configuration and operation of a device or element in a particular orientation. Therefore, the above terms are not intended to restrict the present invention. Further, the terms “first”, “second”, “third”, and the like are used for illustrative purposes only, and are not intended to indicate or imply relative importance. In the present invention, unless otherwise specified or defined, the phrases “mount”, “connect”, “attach”, “fix” and the like, should be understood in a broad sense, and may be understood as, for example, fixed connections, detachable connections, or integral connections; mechanical or electrical connections; direct connections or indirect connections via intermediate structure; or interior communication between two elements. The specific meanings of the above phrases in the present invention can be understood by one skilled in the art in accordance with specific conditions. It should be understood that the embodiments of the present invention are not limited to the specific structures, processing steps or materials disclosed herein, but should extend to equivalent substitutions of these features understood by one ordinarily skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing a particular embodiment only, rather than being construed as restriction. The phrase “an embodiment” or “embodiments” as mentioned in the description means that the particular features, structures or characteristics described in conjunction with the embodiment or embodiments are included in at least one embodiment of the present invention. Thus, the phrase “an embodiment” or “embodiments” used throughout the description does not necessarily refer to the same embodiment. Although the embodiments of the present invention are described hereinabove, the disclosure is provided for facilitating to understand the implementing mode of the present invention, but rather restricting the present invention. Without departing from the spirit and scope of the present disclosure, one skilled in the art can make various modifications and improvements in forms and details of the implementing mode. The scope of protection of the present invention shall be determined by the appending claims.

Claims

1. A system for measuring physical property parameters of fluid in porous medium, comprising:a core device, comprising at least two first-type core modules and a second-type core module arranged therebetween, wherein a core size of a core in the first-type core module is larger than that in the second-type core module; anda control device, configured to control an on / off state of pipelines arranged between adjacent core modules,wherein the control device is further configured to calibrate a pore volume of each core according to an equilibrium pressure when an experimental gas injected into the core device sequentially passes through each core module, and to record the equilibrium pressure when a fluid sample injected into the core device diffuses sequentially to each core module after saturating a first one of the first-type core modules, thereby obtaining the physical property parameters 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 further comprises an injection device, which is configured to inject a first experimental gas to the first one of the first-type core modules in a pore volume calibration stage, and inject a second experimental gas and the fluid sample in a constant composition expansion stage, wherein the fluid sample is provided to simulate fluid in downhole porous medium formation.

3. The system according to claim 2, characterized in that the system further includes a temperature control device, which is configured to provide a simulated formation temperature to the core device.

4. The system according to any one of claims 2-3, characterized in that the system further includes a confining pressure device, which is in communication with asidewall of the core in each core module.

5. The system according to any one of claims 2-4, characterized in that the core modules are connected in series via high-pressure pipelines, wherein a communication valve is arranged at each end of each core module, and a pressure sensor is arranged at each communication valve; andthe system further includes a back pressure device attached to an outlet of the first one of the first-type core modules.

6. The system according to claim 5, characterized in that the control device, in the core pore volume calibration stage, is further configured to:turn on only a communication valve for communicating said injection device and a first core, and record a volume of the first experimental gas injected into the first core and a first value of a first equilibrium pressure;turn on a communication valve for communicating the first core with a second core, and record a second value of the first equilibrium pressure;turn on the communication valves for communicating each core module sequentially, and record other values of the first equilibrium pressure, respectively; andobtain the pore volume of each core separately based on said first value, said second value, and said other values of the first equilibrium pressure.

7. The system according to claim 6, characterized in that the control device, in the constant-composition expansion stage, is further configured to:turn on only the communication valve for communicating the injection device and the first core, and inject the second experimental gas into the first core;adjust the backpressure device to raise a pressure of the first core to a preset formation pressure;allow the fluid sample to be injected into the first core to saturate it, and then turn off the communication valve for communicating the injection device and the firstcore;turn on the communication valve for communicating the first core and the second core, allow the fluid sample in the first core to diffuse into the second core, and record a first value of the second equilibrium pressure;turn on the communication valves for communicating each core module sequentially, and record other values of the second equilibrium pressure; andcalculate the physical property parameters of the fluid sample based on said first value and said 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, whereinthe control device is further configured to plot a curve characterizing a relationship between pressure and pore volume during core expansion, thereby obtaining the saturation pressure of the fluid sample by identifying an inflection point in the curve.

9. The system according to any one of claims 5-8, characterized in that the control device, when calibrating the pore volume of each core, is further configured to subtract a volume of all high-pressure pipelines located before said core from the pore volume of each core.

10. The system according to any one of claims 5-9, characterized in that the control device is further configured to determine numbers of the first-type core modules and the second-type core modules according to steps of:performing a PVT phase state experiment on the fluid sample to measure a solution gas-oil ratio of the formation fluid in a PVT cell, a PVT experiment-based saturation pressure, and a PV relationship curve;calculating a pressure drop value corresponding to each increase in the volume of the formation fluid sample equal to the pore volume of the core based on a PVrelationship in the PV relationship curve where the pressure is greater than the PVT experiment-based saturation pressure, and further calculating a number of the second-type core samples required for a pressure drop from an actual formation pressure to the PVT experiment-based saturation pressure; andcalculating a number of the first-type core samples required for a pressure drop from the PVT experiment-based saturation pressure to a final pressure, wherein said final pressure is a pressure when a volume of the injected fluid sample reaches three times an initial fluid volume required to saturate the first-type core sample.

11. The system according to claim 7 or 8, characterized in that the system further comprises an oil-gas recovery device attached to an outlet of the first one of the first-type core modules, wherein the control device is further configured to obtain gas-oil ratio data from the oil-gas recovery device and determine a timing for completing formation fluid saturation based on changes in the gas-oil ratio data.

12. A method for measuring physical property parameters of fluid in porous medium with the system according to any one of claims 1 to 11, comprising steps of:injecting the first experimental gas into the first one of the first-type core modules;controlling the turning on / off state of pipelines between adjacent core modules via the control device, and continuously recording the equilibrium pressure when the first experimental gas passes through each core module in sequence, thereby calibrating the pore volume of each core;injecting the second experimental gas and the fluid sample into the core device respectively; andcontrolling the turning on / off state of pipelines between adjacent core modules via the control device after the fluid sample saturates the first one of the first-type core modules, and continuously recording the equilibrium pressure when the fluid sample diffuses to each core module in sequence, in order to obtain the physical property parameters of the fluid sample based on the pore volume of each core.INTERNATIONAL SEARCH REPORT International application No. PCT / CN2024 / 104875 A. CLASSIFICATION OF SUBJECT MATTER G01N33 / 24(2006.01)i According to International Patent Classification (IPC) or to both national classification and IPC B. FIELDS SEARCHED Minimum documentation searched (classification system followed by classification symbols) IPC: GO1N33 Documentation searched other than minimum documentation to the extent that such documents are included in the fields searched Electronic data base consulted during the international search (name of data base and, where practicable, search terms used) CNTXT; ENTXTC; VEN, CJFD: gE, ML?, S®, ¢-, EM 7LPX f+W, ffiM rock, multiple, several, first, series, control, pore, volume, pressure C. DOCUMENTS CONSIDERED TO BE RELEVANT Category* Citation of document, with indication, where appropriate, of the relevant passages Relevant to claim No. A CN 114720655 A (CHONGQING UNIVERSITY OF SCIENCE AND TECHNOLOGY) 08 July 2022 (2022-07-08) description, paragraphs 61-89, and figure 1 1-12 A A CN 111257202 A (SOUTHWEST PETROLEUM UNIVERSITY) 09 June 2020 (2020-06-09) entire document CN 105239973 A (CHINA PETROLEUM &CHEMICAL CORPORATION et al.) 13 January 2016 (2016-01-13) entire document 1-12 1-12 A WO 2021053193 Al (UNIVERSITY OF LJUBLJANA) 25 March 2021 (2021-03-25) entire document 1-12 A US 4799382 A (MOBIL OIL CORP.) 24 January 1989 (1989-01-24) entire document 1-12 A US 2020355598 Al (SOUTHWEST PETROLEUM UNIVERSITY) 12 November 2020 (2020-11-12) entire document 1-12 | | Further documents are listed in the continuation of Box C. | J | See patent family annex. * Special categories of cited documents: “T” later document published after the international filing date or priority “A” document defining the general state of the art which is not considered date and not in conflict with the application but cited to understand the to be of particular relevance principle or theory underlying the invention “D” document cited by the applicant in die international application “X” document of particular relevance; the claimed invention cannot be “E" earlier application orpatent but published on or after the international considered novel or cannot be considered to involve an inventive step filing date when the document is taken alone •SL” document which may throw doubts on priority claim(s) or which is “Y” document of particular relevance; the claimed invention cannot be cited to establish the publication date of another citation or other considered to involve an inventive step when the document is special reason (as specified) combined with one or more other such documents, such combination “O” document referring to an oral disclosure, use, exhibition or other being obvious to a person skilled in the art means document member of the same patent family “P” document published prior to the international filing date but later than the priority date claimed Date of the actual completion of the international search 05 November 2024 Date of mailing of the international search report 05 November 2024 Name and mailing address of the ISA / CN China National Intellectual Property Administration (ISA / CN) China No. 6, Xitucheng Road, Jimenqiao, Haidian District, Beijing 100088 Authorized officer Telephone No.

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