A system and method for determining fluid property parameters of a porous medium

Abstract

The application discloses a system and method for measuring fluid physical property parameters of a porous medium, comprising: a core device including at least two first core modules and a plurality of second core modules connected in series between the at least two first core modules; an injection device for injecting a first experimental gas when calibrating a pore volume and injecting a second experimental gas and a fluid sample respectively in a constant volume expansion experiment stage; a confining pressure device for providing a simulated confining pressure to the core device; and an experiment control device for controlling the on-off state of a pipeline between adjacent core modules, wherein the pore volume of each core is calibrated according to recorded equilibrium pressures when the first experimental gas sequentially passes through different core modules, and then the equilibrium pressures when the fluid sample sequentially diffuses to different core modules are recorded when the fluid sample is controlled to saturate a first first core module, so that the physical property parameters of the formation fluid sample are obtained.

Description

Technical Field

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

[0002] The physical properties of oil and gas reservoir fluids are important basic data that are indispensable for determining oil and gas reservoir types, calculating reserves, conducting reservoir engineering and oil production process research, and formulating development plans. Generally, the methods for obtaining the physical properties of oil and gas reservoir fluids are mainly based on the experimental methods formulated in the national standard "Analysis Methods for Physical Properties of Oil and Gas Reservoir Fluids" (GB / T26981-2020). However, with the continuous development of science and technology, experimental technology, experimental equipment, and experimental methods are constantly improving. Today, scholars 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, and the difference between the two increases with the decrease of the pore size in the porous media of the reservoir.

[0003] In the prior art entitled "Calculation Method and System for Fluid Phase State in Porous Media" (CN201910549893.8), based on experimental results, a phase equilibrium calculation model was established that considers the effects of capillary pressure, critical temperature and critical pressure offsets, and pore size distribution in porous media. It was proposed that when the pore size is less than 100nm, porous media will have a significant impact on the phase state of formation fluids. However, because PVT phase state experiments are conducted in a high-temperature, high-pressure, and confined environment, it is extremely difficult to clarify the true phase characteristics of formation fluids in the core.

[0004] In a prior art document titled "A Device for Monitoring Fluid Phase Changes in Porous Media" (CN201410315992.7), a device for monitoring fluid phase changes in porous media was designed. Through perspective windows at both ends of the core holder, the phase changes of the fluid at the core end face can be visually observed. However, a problem with this device is that the fluid observed through the perspective windows is no longer the state of the fluid within the porous medium of the core, but rather the state of the fluid in the bulk phase space (similar to the state in a PVT cylinder).

[0005] In the prior art entitled “Device and Experimental Method for Fluid Phase Testing in Porous Media” (CN201810297660.9), a device integrating ultrasonic detection, microscopic visualization, and multi-point pressure monitoring methods was designed to study the phase characteristics of fluids in porous media. However, the fluid observed by the visualization technology in this device is no longer the state of the fluid in the porous medium of the core, but the state of the fluid entering the bulk phase space (the same as the state in the PVT cylinder). However, due to the very small amount of saturated fluid in the core, ultrasonic detection technology causes severe noise interference and is unable to detect the acoustic wave signal of the fluid itself. Therefore, it is difficult to clearly determine the phase characteristics of the fluid in the porous medium using this device.

[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 fluid phase state in porous media have some problems, which leads to great limitations in the experimental results and cannot reflect the true situation of the fluid phase state in the core. Summary of the Invention

[0008] 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.

[0009] To solve the above technical problems, an embodiment of the present invention provides a system for measuring physical properties of porous media fluids, comprising: a core device comprising at least two first-type core modules and a plurality of second-type core modules connected in series between the at least two first-type core modules, wherein the core size of the first-type core modules is larger than the core size of the second-type core modules; an injection device for injecting a first experimental gas during pore volume calibration and injecting a second experimental gas and a fluid sample during a constant mass expansion experiment; a confining pressure device for providing a simulated confining pressure to the core device; and an experiment control device for controlling the on-off state of pipelines between adjacent core modules, wherein the pore volume of each core is calibrated based on the recorded equilibrium pressure when the first experimental gas passes through the core modules at different positions in sequence, and then, while controlling the fluid sample to saturate the first first-type core module, the equilibrium pressure when the fluid sample diffuses to the core modules at different positions in sequence is recorded, and the physical properties of the formation fluid sample are obtained in combination with the pore volume of each core.

[0010] Preferably, the injection device includes: a double-cylinder plunger pump, which is used to transmit pressure to a piston container through a pressurized medium; a piston container, which is used to use the provided pressure power to inject the first experimental gas or the second experimental gas or the fluid sample into the first first-type core module, the first experimental gas is preferably helium, and the second experimental gas is preferably natural gas.

[0011] Preferably, the first / second type core module includes: a first / second type core, a core holder and a core casing, the size range of the first type core is a core diameter of 10 cm and a core length of 3-15 cm, and 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.

[0012] Preferably, the core casing is a heating casing, wherein the system further comprises: a temperature control device, wherein the temperature control device is used to provide simulated formation temperature to the core device.

[0013] Preferably, the confining pressure device is connected to the core sidewalls in each of the core modules, and the confining pressure device adopts a double-cylinder plunger pump.

[0014] Preferably, the core modules are connected in series through a high-pressure series pipeline, wherein a corresponding connecting valve is provided at the end of each core module, and a pressure sensor for measuring the equilibrium pressure 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 experimental control device carries out a calibration experiment of the core pore volume according to the following steps: controlling the confining pressure device to apply confining pressure to each core module; controlling the connecting valve provided on the end face of each core module to open, thereby vacuuming all cores; controlling the connecting valve for connecting each core module in series to close; controlling the injection device to inject the first experimental gas from the inlet of the core device, and recording the volume of gas injected into the first core, and the first equilibrium pressure after the pressure stabilizes; 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, thereby recording the first equilibrium pressure after the pressure stabilizes by sequentially controlling the connecting valve for connecting each core module in series to open; obtaining the pore volume of each core according to the first equilibrium pressure recorded at different time periods.

[0016] Preferably, the experimental control device carries out the constant-quality expansion experiment according to the following steps: controlling the connecting valve provided at the end face of each core module to open, thereby evacuating all cores; controlling the connecting valve for connecting the core modules in series to close; controlling the injection device to inject the second experimental gas from the inlet of the core device, and raising the pressure of the first core to a preset formation pressure by controlling the regulation of the back pressure device; controlling the injection device to inject the fluid sample from the inlet of the core device, so that the fluid sample displaces the first core and completes formation fluid saturation; controlling the valve provided at the inlet of the core device to close; controlling the connecting valve for connecting the first core and the second core to open, so that the formation fluid in the first core diffuses to the second core, and recording the current second equilibrium pressure after the pressure stabilizes. Similarly, by sequentially controlling the connecting valve for connecting the core modules in series to open, the second equilibrium pressure after the pressure stabilizes is recorded respectively; and calculating the physical properties of the formation fluid sample based on the second equilibrium pressure at different time periods and the pore volume of each core.

[0017] Preferably, the physical property parameters include saturation pressure, wherein the step of calculating the saturation pressure of the formation fluid sample includes: drawing a curve characterizing the relationship between pressure and pore volume during the core expansion process, thereby obtaining the saturation pressure of the formation fluid sample by identifying the inflection point in the current pressure and pore volume relationship curve.

[0018] Preferably, the length of the high-pressure serial pipeline is 3-5 cm, wherein the pore volume of each core is also deducted from the volume of the high-pressure serial pipeline located at the front end of the corresponding core.

[0019] Preferably, the experimental control device is also used to configure the number of the first type of core modules and the second type of core modules according to the following step process: conducting a PVT phase experiment on the formation fluid sample, determining the dissolved gas-oil ratio of the formation fluid in the PVT tube, the saturation pressure and the pressure-volume relationship curve based on the PVT experiment, and determining the porosity and permeability of the first type of core samples and the second type of core samples through a core analysis method; calculating the pressure drop value corresponding to each unit increase in the core pore volume of the formation fluid sample based on the PV relationship in the pressure-volume relationship curve that is greater than the saturation pressure based on the PVT experiment, and based on this, calculating the number of the second type of 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 of 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 of core sample.

[0020] Preferably, the back pressure device comprises: a back pressure pump and a back pressure valve, and the back pressure pump is a single-cylinder plunger pump.

[0021] Preferably, the system also includes an oil and gas recovery device hung at the outlet of the first first-type core module, and the oil and gas recovery device includes an oil and gas separation bottle and a gas meter, wherein the experimental control device is also used 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.

[0022] On the other hand, a method for measuring physical parameters of porous medium fluid is provided, the method being implemented by the system as described above, wherein the method comprises: constructing a core device, the core device comprising at least two first-type core modules and a plurality of second-type core modules connected in series between the at least two first-type core modules, wherein the core size of the first-type core module is larger than the core size of the second-type core module; a confining pressure device providing a simulated confining pressure to the core device; an injection device injecting a first experimental gas during pore volume calibration; an experimental control device controlling the gaps between adjacent core modules by adjusting the gaps between adjacent core modules; The pipeline on-off state is controlled, and the equilibrium pressure when the first experimental gas passes through the core modules at different positions in sequence is continuously recorded, so as to calibrate the pore volume of each core; the injection device injects the second experimental gas and the fluid sample respectively during the constant mass expansion experiment stage; the experimental control device controls the pipeline on-off state between adjacent core modules while controlling the fluid sample to saturate the first first-type core module, and continuously records the equilibrium pressure when the fluid sample diffuses to the core modules at different positions in sequence, and obtains the physical properties of the formation fluid sample in combination with the pore volume of each core.

[0023] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0024] The present invention proposes a system and method for measuring the physical properties of porous medium fluids. The system and method are mainly composed of multiple full-diameter cores and short cores connected in series, which are used to simulate the process of constant mass expansion of formation fluids in a reservoir. By measuring the pressure and corresponding volume of the fluid during the expansion process in the core, the saturation pressure of the formation fluid and its related high-pressure physical properties are determined. Therefore, the present invention can directly measure the relationship between the pressure and corresponding 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 porous medium of the reservoir, 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.

[0025] 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

[0026] 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:

[0027] Figure 1 Schematic diagram of the overall structure of a system for measuring physical properties of porous medium fluid according to an embodiment of the present application.

[0028] Figure 2 Schematic diagram of the specific structure of the system for measuring the physical properties of porous medium fluid according to an embodiment of the present application.

[0029] Figure 3 Schematic diagram of the implementation process of the system for measuring physical properties of porous medium fluid according to an embodiment of the present application.

[0030] Figure 4 Schematic diagram of the comparison effect of the PV relationship curve measured by the system for measuring the physical properties of porous medium fluid according to the embodiment of the present application and the traditional PVT cylinder.

[0031] Figure 5 Schematic diagram of the comparison effect of the inflection point in the PV relationship curve measured by the system for measuring the physical properties of porous medium fluids according to an embodiment of the present application and a traditional PVT cylinder.

[0032] Figure 6 Schematic diagram of the steps of a method for measuring physical properties of porous medium fluid according to an embodiment of the present application. DETAILED DESCRIPTION

[0033] 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.

[0034] 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.

[0035] 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.

[0036] The physical properties of oil and gas reservoir fluids are important basic data that are indispensable for determining oil and gas reservoir types, calculating reserves, conducting reservoir engineering and oil production process research, and formulating development plans. Generally, the methods for obtaining the physical properties of oil and gas reservoir fluids are mainly based on the experimental methods formulated in the national standard "Analysis Methods for Physical Properties of Oil and Gas Reservoir Fluids" (GB / T26981-2020). However, with the continuous development of science and technology, experimental technology, experimental equipment, and experimental methods are constantly improving. Today, scholars 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, and the difference between the two increases with the decrease of the pore size in the porous media of the reservoir.

[0037] In the prior art entitled "Calculation Method and System for Fluid Phase State in Porous Media" (CN201910549893.8), based on experimental results, a phase equilibrium calculation model was established that considers the effects of capillary pressure, critical temperature and critical pressure offsets, and pore size distribution in porous media. It was proposed that when the pore size is less than 100nm, porous media will have a significant impact on the phase state of formation fluids. However, because PVT phase state experiments are conducted in a high-temperature, high-pressure, and confined environment, it is extremely difficult to clarify the true phase characteristics of formation fluids in the core.

[0038] In a prior art document titled "A Device for Monitoring Fluid Phase Changes in Porous Media" (CN201410315992.7), a device for monitoring fluid phase changes in porous media was designed. Through perspective windows at both ends of the core holder, the phase changes of the fluid at the core end face can be visually observed. However, a problem with this device is that the fluid observed through the perspective windows is no longer the state of the fluid within the porous medium of the core, but rather the state of the fluid in the bulk phase space (similar to the state in a PVT cylinder).

[0039] In the prior art entitled “Device and Experimental Method for Fluid Phase Testing in Porous Media” (CN201810297660.9), a device integrating ultrasonic detection, microscopic visualization, and multi-point pressure monitoring methods was designed to study the phase characteristics of fluids in porous media. However, the fluid observed by the visualization technology in this device is no longer the state of the fluid in the porous medium of the core, but the state of the fluid entering the bulk phase space (the same as the state in the PVT cylinder). However, due to the very small amount of saturated fluid in the core, ultrasonic detection technology causes severe noise interference and is unable to detect the acoustic wave signal of the fluid itself. Therefore, it is difficult to clearly determine the phase characteristics of the fluid in the porous medium using this device.

[0040] 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.

[0041] In summary, most of the current research devices and methods for the fluid phase state in porous media have some problems, which leads to great limitations in the experimental results and cannot reflect the true situation of the fluid phase state in the core.

[0042] Therefore, to address one or more of the aforementioned technical issues, this application proposes a system and method for determining 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.

[0043] Figure 1 Schematic diagram of the overall structure of the system for measuring the physical parameters of porous medium fluid according to the embodiment of the present application. Figure 1 As shown, the system for measuring the physical properties of porous medium fluid (also called "physical property parameter measurement system") according to the embodiment of the present invention includes: a core device A, an injection device B, a confining pressure device C and an experimental control device D.

[0044] The core device A includes: at least two first-type core modules A1 and several second-type core modules A2 connected in series between the at least two first-type core modules. In an embodiment of the present invention, the core modules are connected in series via a high-pressure series pipeline. First, several second-type core modules A2 are connected in series via a high-pressure series pipeline to form a second-type core module sequence. Then, at least two first-type core modules A1 are respectively arranged at the two end faces of the second-type core module sequence, that is, one first-type core module A1 is arranged at the end face at the entrance of the second-type core module sequence, and the remaining first-type core modules A1 are arranged at the end face at the exit of the second-type core module sequence. Similarly, the first-type core module A1 and its adjacent second-type core module A2 are connected in series via a high-pressure series pipeline. In this embodiment of the present invention, the end faces of the cores in adjacent core modules are arranged relative to each other.

[0045] 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.

[0046] The injection device B is connected to the inlet of the first type 1 core module A1 in the core device A through a high pressure injection line 22. Figure 2 In addition, if Figure 2 As shown, a high-pressure output pipeline 29 is provided at the outlet of the last first-type core module A1 in the core device A. The injection device B is used to inject experimental gas during the pore volume calibration phase and to inject formation fluid samples during the constant mass expansion experiment phase.

[0047] 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.

[0048] The experimental 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 experimental 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.

[0049] Experimental control device D continuously records the equilibrium pressure (recorded as the first equilibrium pressure) when the first experimental gas passes through core modules 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, experimental 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 to saturate the first type-one core module A1. It continuously records the equilibrium pressure (recorded as the second equilibrium pressure) when the formation fluid sample diffuses to core modules 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.

[0050] 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.

[0051] Figure 2 This is a schematic diagram of the specific structure of the system for measuring the physical parameters of porous medium fluids according to the embodiment of the present application. Figure 2 , the specific structure of the physical property parameter measurement system described in the embodiment of the present invention is described.

[0052] like Figure 2 As shown, the first type core module A1 includes: a first type core 2, core holders 1 and 10 (full diameter core holders), and a core sleeve 6. In one embodiment, the size range of the first type core is 10 cm in diameter and 3-15 cm in length. The second type core module A2 includes: a second type core 4, core holders 3, 5, 7, 8, 9 (short core holders), and a core sleeve 6. In one embodiment, the size range of the second type core is 1.8-3.8 cm in diameter and 1-15 cm in length.

[0053] Each core module A1 and A2 is provided with a corresponding connecting valve 11, 13, 15, 16, 17, etc. at its end 18. Specifically, a corresponding connecting valve is provided 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 valves on each high-pressure series pipeline, high-pressure injection pipeline, and high-pressure output pipeline are three-way valves.

[0054] 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 the full-diameter core holder 1 is first saturated with high-pressure formation fluid, and then the fluid in 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. After the full-diameter core 2 in the full-diameter core holder 1 is fully saturated with formation fluid, it is connected to a connecting valve 13 via a 1 / 16-inch high-pressure serial line 12, and then to the 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.

[0055] 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.

[0056] 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.

[0057] refer to Figure 2, the injection device B includes: a double-cylinder plunger pump 19 and a piston container 21. The two plunger pumps in the double-cylinder plunger pump 19 are respectively connected to the two-way storage containers in the piston container 21 through the corresponding two-way valves 20. The double-cylinder plunger pump 19 is used to transmit pressure to the piston container through the pressure medium. The piston container 21 is used to use the pressure power provided to inject the first experimental gas or the second experimental gas or the formation fluid sample into the first first-type core module A1. The first experimental gas is preferably helium. The second experimental gas is preferably natural gas. 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.

[0058] 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.

[0059] 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 temperature 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.

[0060] 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.

[0061] In this embodiment of the present invention, a two-way valve 14 is installed at the front end of the back-pressure valve 25. The two-way valve 14 controls the connection between the back-pressure device and the first first-type core module A1. Specifically, the two-way valve 14 is installed at the front end of the back-pressure valve 25. The experimental 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; when saturation is complete, the two-way valve 14 needs to be closed.

[0062] 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.

[0063] 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.

[0064] Figure 3 The following is a schematic diagram of the implementation process of the system for measuring the physical parameters of porous medium fluids in the embodiment of the present application. Figure 3 , the specific implementation process of the physical property parameter measurement system described in the embodiment of the present invention is described.

[0065] Before the system is set up (before the experiment begins), the number of first-type core modules and the number of second-type core modules need to be configured using the above-mentioned experimental control device D according to the following steps. Specifically, first, a PVT phase state experiment is performed on the formation fluid sample to determine 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. In addition, the porosity and permeability of the first-type core sample and the second-type core sample are determined by 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 the core pore volume of the formation fluid sample is calculated. Based on the pressure drop corresponding to the 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.

[0066] Specifically, before the experiment begins, a PVT phase state test is performed on the formation fluid samples tested in accordance with the national standard "Methods for Physical Property Analysis of 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 tube. Furthermore, the porosity and permeability of several core samples, including full-diameter core 2 and short core 4, are measured according to the national standard "Core Analysis Method" (GB / T 29172-2012). The saturation pressure measured from the PVT experiment is then used to calculate the saturation pressure difference (i.e., the difference between the formation pressure and the saturation pressure). Combined with the PV curve of the formation fluid sample, where the pressure is greater than the saturation pressure, the pressure drop corresponding to each increase in the core pore volume is calculated. This allows the number of short cores required to reduce the initial formation pressure to the saturation pressure measured from the PVT experiment (PVT tube measurement) to be calculated. In addition, it is also necessary to calculate the number of cores required when the pressure in the PV curve continues to drop from the saturation pressure to the final pressure (that is, the pressure corresponding to 3 times the initial fluid volume), which is the number of core samples of the first type.

[0067] 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 short core with a large pore volume or a full-diameter core 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.

[0068] Then, the experimental control device D first controls the experiment of calibrating the pore volume of each core under the action of confining pressure. The experimental control device D performs the calibration experiment of the core pore volume according to the following steps:

[0069] Control the confining pressure device C to apply confining pressure to each core module A1 and A2;

[0070] Control the connecting valves set on the end faces of each core module A1 and A2 to open, thereby vacuuming all cores;

[0071] Control the closing of the connecting valves for connecting the core modules A1 and A2 in series;

[0072] 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;

[0073] 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;

[0074] 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;

[0075] The pore volume of each core was obtained based on the first equilibrium pressure recorded at different time periods.

[0076] Specifically, S1. The experimental 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 experimental control device D opens and controls all valves 11, 13, 15, 16, etc. set on the end face of each core module; S3. The experimental control device D controls all cores to be vacuumed at the same time from the three-way valves 11 and 17 respectively, until the experimental control device D detects that the readings of the pressure sensors corresponding to all cores are consistent; S4. The experimental 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 experimental 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 experimental control device D records the constant pressure. The volume of helium V1 injected into 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 experimental 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 experimental 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.

[0077] Next, the experiment control device D continues to control the saturated formation fluid experiment and fluid physical parameter measurement experiment of the full-diameter core 2 under the action of confining pressure. The experiment control device D conducts the constant mass expansion experiment according to the following steps:

[0078] Control the connecting valves set on the end faces of each core module A1 and A2 to open, thereby vacuuming all cores;

[0079] Control the closing of the connecting valves for connecting the core modules A1 and A2 in series;

[0080] 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;

[0081] 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;

[0082] Control the valve at the inlet of the core device A to close;

[0083] 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;

[0084] 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;

[0085] 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.

[0086] In one embodiment, the high-pressure physical property parameter includes saturation pressure. Specifically, in the process of calculating the saturation pressure, a curve representing the relationship between pressure and pore volume during the core expansion process is plotted based on the second equilibrium pressure at different time periods and the pore volume of each core. The saturation pressure of the formation fluid sample is obtained by identifying the inflection point in the current pressure-pore volume relationship curve.

[0087] Specifically, M1. The experimental control device D re-evacuates all the cores in series, and the vacuuming method refers to the above steps S1 to S3; M2. The experimental 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 experimental 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 experimental 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.

[0088] In one embodiment, the experimental 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, formation fluid saturation is determined to have been completed.

[0089] Next, M5, when the full-diameter core 2 is saturated with formation fluid, the experimental control device D closes the three-way valve 11 and the two-way valve 14; M6, the experimental 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 experimental control device D records the pressure at this time and records it as the second equilibrium pressure; M7, the experimental control device D opens the three-way valve 15 again to allow the formation fluid sample to diffuse into the short core 4 again. The formation fluid sample is dispersed into 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 experimental 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 experimental 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 and the corresponding core pore volume obtained in steps M6-M8, the corresponding relationship between the pressure and pore volume during the expansion of the formation fluid 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).

[0090] Furthermore, since the calibrated pore volume of each core includes the volume of the fluid within 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 still affects the measurement results. Therefore, in this embodiment of the present invention, the pore volume of each core is further subtracted from the (total) volume of the high-pressure serial pipeline located at the front end of the corresponding core, that is, the impact of the volume of the high-pressure serial pipeline on the measurement results needs to be eliminated.

[0091] 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).

[0092] 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.

[0093] 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.

[0094] (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 obtained the pressure-volume (PV) relationship curve. In addition, it is necessary to measure the porosity and permeability of several core samples, including full-diameter cores and short cores, in accordance with the national standard "Core Analysis Method" (GB / T29172-2012).

[0095] (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.

[0096] Table 1 Core parameters

[0097]

[0098]

[0099] (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.

[0100] (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.

[0101] (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).

[0102] Experimental results:

[0103] Table 1 shows the relationship between the core pressure and its corresponding cumulative core pore volume (including the corrected volume after deducting the dead volume in the pipeline) during the constant mass expansion of condensate gas. After plotting the core pressure and the core cumulative corrected pore volume in the same coordinate system, we can obtain: Figure 4 The pressure-volume (PV) curve measured in the core is shown in the figure; the other curve shows the PV curve measured in the PVT tube as a comparison reference. Figure 4 The inflection points of the two different curves can be obtained by enlarging the two curves separately. Figure 5 (a) and Figure 5 (b). Figure 5 (a) shows the inflection point of the PV relationship curve measured in the PVT cylinder after amplification. 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 reveals that the condensate dew point pressure measured in the core is higher than that measured in the PVT cylinder, indicating that the presence of porous media can increase the dew point pressure of the condensate gas by 7.1%.

[0104] 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 physical property parameters of porous medium fluid (also referred to as "physical property parameter measurement method"). The physical property parameter measurement method is implemented using the above-mentioned physical property parameter measurement system.

[0105] Figure 6 Schematic diagram of the steps of the method for measuring the physical parameters of porous medium fluid according to the embodiment of the present application. Figure 6 As shown, the method for measuring physical property parameters according to the embodiment of the present invention includes the following steps:

[0106] Step S601: constructing a core device, the core device comprising at least two first-type core modules and a plurality of second-type core modules connected in series between the at least two first-type core modules, wherein the core size of the first-type core module is larger than the core size of the second-type core module;

[0107] Step S602: The confining pressure device provides simulated confining pressure to the core device;

[0108] Step S603: The injection device B connected to the first first-type core module A1 in the core device A injects a first experimental gas during pore volume calibration;

[0109] Step S604: The experiment control device D controls the on / off status of the pipelines between adjacent core modules and continuously records the equilibrium pressure when the first experiment gas passes through the core modules at different positions in sequence, thereby calibrating the pore volume of each core;

[0110] Step S605: The injection device B injects the second experimental gas and the fluid sample respectively during the constant mass expansion experiment phase;

[0111] Step S606: The experimental control device D controls the fluid sample to saturate the first first-type core module. By controlling the on-off status of the pipelines between adjacent core modules, it continuously records the equilibrium pressure when the fluid sample diffuses to the core modules at different positions in sequence, and obtains the physical properties of the formation fluid sample in combination with the pore volume of each core.

[0112] The present invention discloses a system and method for measuring the physical properties of porous medium fluids. 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 measuring the pressure of the fluid during the expansion process in the core and its corresponding volume, the saturation pressure of the formation fluid and its related high-pressure physical properties are determined. As a result, the present invention can directly measure the relationship between the pressure of the formation fluid during the expansion process in the porous medium of the actual reservoir and its corresponding volume, 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 porous medium of the reservoir, and provide objective basic parameters for the development plan design, reserve calculation and oil test and production of low-porosity and low-permeability oil and gas reservoirs, which has extremely wide promotion and application value.

[0113] 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.

[0114] 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.

[0115] 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.

[0116] 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.

[0117] 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.

[0118] 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 porous medium fluid, characterized in that: include: A core device comprising at least two first-type core modules and a plurality of second-type core modules connected in series between the at least two first-type core modules, wherein the core size of the first-type core modules is larger than the core size of the second-type core modules; An injection device, which is used to inject a first experimental gas during pore volume calibration and to inject a second experimental gas and a fluid sample during a constant mass expansion experiment; a confining pressure device, which is used to provide simulated confining pressure to the core device; An experimental control device is used to control the on-off state of pipelines between adjacent core modules, wherein the pore volume of each core is calibrated according to the equilibrium pressure recorded when the first experimental gas passes through the core modules at different positions in sequence, and then, under the condition that the fluid sample is controlled to saturate the first first-type core module, the equilibrium pressure when the fluid sample diffuses to the core modules at different positions in sequence is recorded, and the physical properties of the formation fluid sample are obtained in combination with the pore volume of each core, wherein, The core modules are connected in series via a high-pressure series pipeline, wherein a corresponding connecting valve is provided at the end of each core module, and a pressure sensor for measuring the equilibrium pressure is provided at each connecting valve, wherein the system further comprises a back-pressure device connected to the outlet of the first first-type core module, wherein the pore volume of each core is also deducted from the volume of the high-pressure series pipeline located at the front end of the corresponding core.

2. The system according to claim 1, wherein: The injection device comprises: A double-cylinder plunger pump, which is used to transmit pressure to the piston container via a pressurized medium; A piston container is used to inject the first experimental gas or the second experimental gas or the fluid sample into the first first-type core module using the provided pressure power, wherein the first experimental gas is helium and the second experimental gas is natural gas.

3. The system according to claim 1, wherein: The first / second type core module includes: a first / second type core, a core holder and a core casing. The size range of the first type core is a core diameter of 10 cm and a core length of 3-15 cm. 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.

4. The system according to claim 3, characterized in that The core casing is a heating casing, wherein the system further comprises: a temperature control device, wherein the temperature control device is used to provide simulated formation temperature to the core device.

5. The system according to any one of claims 1 to 4, characterized in that: The confining pressure device is connected to the core side wall in each core module, and the confining pressure device adopts a double-cylinder plunger pump.

6. The system according to claim 1, wherein: The experimental control device carries out the core pore volume calibration experiment according to the following steps: controlling the confining pressure device to apply confining pressure to each core module; Control the connecting valves provided at the end faces of each core module to open, thereby evacuating all cores; Controlling the connecting valves for connecting the core modules in series to close; controlling the injection device to inject the first experimental gas from the inlet of the core device, and recording the volume of the gas injected into the first core and the first equilibrium pressure after the pressure stabilizes; Controlling the opening of a connecting valve for connecting the first core block and the second core block, and recording the current first equilibrium pressure after the pressure stabilizes, thereby recording the first equilibrium pressure after the pressure stabilizes by sequentially controlling the opening of the connecting valves for each core module connected in series; The pore volume of each core is obtained according to the first equilibrium pressure recorded at different time periods.

7. The system according to claim 6, characterized in that The experimental control device carries out the constant quality expansion experiment according to the following steps: Control the connecting valves provided at the end faces of each core module to open, thereby evacuating all cores; Controlling the connecting valves for connecting the core modules in series to close; Controlling the injection device to inject the second experimental gas from the inlet of the core device, and controlling the back pressure device to increase the pressure of the first core to a preset formation pressure; controlling the injection device to inject the fluid sample from the inlet of the core device so that the fluid sample displaces the first core block to complete formation fluid saturation; Controlling the closure of a valve provided at the inlet of the core device; 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, recording the current second equilibrium pressure after the pressure stabilizes, and similarly, sequentially controlling the opening of connecting valves for each core module connected in series to record the second equilibrium pressure after the pressure stabilizes; The physical property parameters of the formation fluid sample are calculated according to the second equilibrium pressure at different time periods and the pore volume of each core.

8. The system according to claim 7, characterized in that The physical property parameter includes saturation pressure, wherein the step of calculating the saturation pressure of the formation fluid sample includes: A curve representing the relationship between pressure and pore volume during the core expansion process is drawn, and the saturation pressure of the formation fluid sample is obtained by identifying the inflection point in the current pressure-pore volume relationship curve.

9. The system according to claim 1, wherein: The length of the high-pressure series pipeline is 3-5 cm.

10. The system according to claim 1, wherein: The experimental control device is further used to configure the number of the first type core modules and the second type core modules according to the following steps: Conduct PVT phase state experiments on formation fluid samples to determine the dissolved gas-oil ratio of the formation fluid in the PVT cylinder, the saturation pressure and pressure-volume relationship curve based on the PVT experiment, and determine the porosity and permeability of the first and second type core samples through core analysis methods; Based on 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 corresponding to each unit increase in core pore volume of the formation fluid sample, and based on this, calculating the number of second-type core samples required to reduce the actual formation pressure to the saturation pressure based on the PVT experiment; The number of first-type 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 core samples.

11. The system according to claim 1, wherein: The back pressure device comprises a back pressure pump and a back pressure valve, and the back pressure pump is a single-cylinder plunger pump.

12. The system according to claim 7, wherein: The system also includes an oil and gas recovery device hung at the outlet of the first first-type core module, and the oil and gas recovery device includes an oil and gas separation bottle and a gas meter. The experimental control device is also used 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.

13. A method for measuring physical properties of porous medium fluid, characterized in that: The method is implemented using the system according to any one of claims 1 to 12, wherein the method comprises: Constructing a core device, the core device comprising at least two first-type core modules and a plurality of second-type core modules connected in series and positioned between the at least two first-type core modules, wherein a core size of the first-type core module is larger than a core size of the second-type core module; The confining pressure device provides simulated confining pressure to the core device; injecting a first experimental gas by an injection device during pore volume calibration; The experimental control device controls the on / off status of the pipelines between adjacent core modules and continuously records the equilibrium pressure when the first experimental gas passes through the core modules at different positions in sequence, thereby calibrating the pore volume of each core; The injection device injects the second experimental gas and the fluid sample respectively during the constant mass expansion experiment stage; The experimental control device controls the fluid sample to saturate the first first-type core module, controls the on-off status of the pipelines between adjacent core modules, continuously records the equilibrium pressure when the fluid sample diffuses to the core modules at different positions in sequence, and obtains the physical properties of the formation fluid sample in combination with the pore volume of each core.

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