Experimental apparatus and method for simulating long-distance transportation in deepwater field

Abstract

The present application relates to the technical field of oil and gas development, and provides an experimental apparatus and method for simulating long-distance transportation in a deepwater field. The experimental apparatus comprises: a formation oil displacement simulation unit, a wellbore oil production simulation unit, and a subsea gathering and transportation simulation unit, wherein the three units can be communicated with each other by means of piping. The formation oil displacement simulation unit comprises a first core oil holder, a second core oil holder, a gas injection apparatus, and a water injection apparatus, wherein both oil holders can be connected to the gas injection apparatus and the water injection apparatus. The experimental apparatus provided in the present application can realistically simulate the conditions of wellbore oil production and surface gathering and transportation, and can also simulate two production modes, i.e., oil displacement by gas injection and oil displacement by water injection, and two drive modes, i.e., single-pressurization pump drive and pump-free shear circulation drive, thereby solving the problems in conventional apparatuses that a circulation pump repeatedly shears a fluid, destroys the internal structure of the fluid, and affects flow parameters.

Description

Experimental apparatus and methods for simulating long-distance transportation in deepwater oilfields

[0001] This application claims priority to Chinese Patent Application No. 202411423357.0, filed on October 12, 2024, entitled "Experimental Apparatus and Method for Simulating Long-Distance Transportation in Deepwater Oilfields", the entire contents of which are incorporated herein by reference. Technical Field

[0002] This application relates to the field of oil and gas development technology, and in particular to an experimental device and method for simulating long-distance transportation in deep-water oilfields. Background Technology

[0003] With the gradual depletion of onshore and shallow-water oil resources, the exploration and development of deep-water oil, gas, and water resources is an inevitable choice to meet the growing global energy demand. These regions contain abundant oil and natural gas resources, but the high pressure, low temperature, complex topography, and harsh marine environment of the deep seabed pose more severe challenges to the development and transportation of oil and gas.

[0004] In deepwater oil and gas development, oil, gas, and water typically exist in multiphase flow. Multiphase flow transportation involves the mixed flow of three-phase fluids—oil, gas, and water—and its complex flow behavior can easily lead to problems such as flow instability, phase separation, and blockage. Therefore, research on multiphase flow transportation technology has become crucial for solving the problem of long-distance transportation in deepwater oilfields.

[0005] Current research on deepwater multiphase flow transportation technology at home and abroad mainly focuses on the generation mechanism and flow characteristics of severe slug flow in wellbore or riser systems, the variation law of flow induction force in gas-liquid two-phase flow in risers, vortex-induced vibration of suspended sections of subsea pipelines, multiphase flow law of subsea oil and gas pipelines, and fluid flow process in long-distance mixed-transport pipeline systems. However, research on the characteristics of multiphase flow in long-distance transportation paths in deepwater oilfields, including the influence of factors such as different temperatures, pressures, ocean current velocities, and seabed topography on the flow regime and pressure loss characteristics of multiphase fluids, is still relatively lacking. Summary of the Invention

[0006] In view of the above problems, this application provides an experimental device and method for simulating long-distance transportation in deep-water oilfields. The experimental device integrates formation oil displacement, wellbore oil production, and surface gathering and transportation, and can realistically simulate wellbore oil production and surface gathering and transportation.

[0007] To achieve the above objectives, this application provides an experimental device for simulating long-distance transportation in deepwater oilfields, comprising: a formation displacement simulation unit, including a first core oil reservoir, a second core oil reservoir, an injection gas device, and a water injection device; the air inlets of the first and second core oil reservoirs are both connected to the injection gas device, and the water inlets of the first and second core oil reservoirs are both connected to the water injection device, and the first and second core oil reservoirs are interconnected; a wellbore oil production simulation unit, the inlet of which is connected to the outlets of the first and second core oil reservoirs, and the injection gas device and the water injection device are both connected to the wellbore oil production simulation unit; and an underwater gathering and transportation simulation unit, the inlet of which is connected to the outlet of the wellbore oil production simulation unit, and the outlet of which is connected to the inlet of the first and second core oil reservoirs.

[0008] In one possible implementation, both the wellbore oil production simulation unit and the underwater gathering and transportation simulation unit are equipped with retractable pressurized samplers that can extend into or retract outside the fluid pipeline.

[0009] In one possible implementation, the underwater gathering and transportation simulation unit includes: a wellhead surface flow unit, the inlet end of which is connected to the outlet end of the wellbore oil production simulation unit; and a marine riser flow unit, the inlet end of which is connected to the outlet end of the wellhead surface flow unit, and the outlet end of which is connected to the inlet of the first core oil storage device and the inlet of the second core oil storage device.

[0010] In one possible implementation, the marine riser flow unit includes: an ocean current simulation tank; a riser, disposed inside the ocean current simulation tank and oscillatingly arranged along the height direction of the ocean current simulation tank; the inlet end of the riser is connected to the outlet end of the wellhead surface flow unit, and the outlet end of the riser is connected to the inlet of the first core oil storage tank and the inlet of the second core oil storage tank; and a water flow control device, connected to the ocean current simulation tank, for injecting water into the ocean current simulation tank and regulating the water flow rate inside the ocean current simulation tank.

[0011] In one possible implementation, the water flow control device includes: a water storage unit; and multiple pumping components, each pumping component being connected between the water storage unit and the ocean current simulation tank, and the pumping components being arranged sequentially along the height direction of the ocean current simulation tank.

[0012] In one possible implementation, the pumping assembly includes a pumping pipe connected between the water storage vessel and the ocean current simulation tank, as well as a water pump, a flow meter, and a check valve disposed on the pumping pipe.

[0013] In one possible implementation, hoses are provided on both sides of the ocean current simulation tank in the height direction, and the inlet and outlet ends of the riser are connected to the hoses.

[0014] In one possible implementation, the pressurized sampler includes: a sampling line, the inlet end of which is detachably connected to a fluid pipe, and the outlet end of which is provided with a back pressure valve; a drainage tube, which communicates with the inlet end of the sampling line and is movable radially along the fluid pipe; and a drive assembly, which is connected between the fluid pipe and the inlet end of the sampling line for driving the drainage tube to move.

[0015] In one possible implementation, the sampling pipeline includes a first short pipe, a pressurized sampling pipe, and a second short pipe connected in sequence via a ball valve. The other end of the first short pipe is connected to the drive assembly via a ball valve, and the back pressure valve is connected to the other end of the second short pipe.

[0016] In one possible implementation, the drive assembly includes: a housing connected to a fluid conduit; a fixed tube, one end of which is located inside the housing, and the other end of which extends outside the housing and is connected to a sampling conduit; a positioning piston movably disposed between the fixed tube and the housing, and together with the fixed tube and the housing, forming a fluid cavity with a variable volume; and a drive pump connected to the fluid cavity for driving the positioning piston to move; wherein a drainage tube is connected to the positioning piston and communicates with the fixed tube.

[0017] In one possible implementation, the experimental apparatus for simulating long-distance transportation in deepwater oilfields further includes: a buffer tank connected between the outlet of the underwater gathering and transportation simulation unit and the inlet of the first core storage tank and the inlet of the second core storage tank; and a plunger pump connected between the buffer tank and the pressure source.

[0018] In one possible implementation, the experimental apparatus for simulating long-distance transportation in deepwater oilfields further includes a separator connected between the liquid outlet of the underwater gathering and transportation simulation unit and the buffer tank.

[0019] In one possible implementation, multiple transparent pipe sections are provided in the fluid pipelines of the wellbore oil production simulation unit and the underwater gathering and transportation simulation unit.

[0020] In one possible implementation, an experimental method for simulating long-distance transportation in deepwater oilfields includes: placing crude oil into a first core storage tank or a second core storage tank; activating a gas injection device or a water injection device to inject gas or liquid into the first core storage tank or the second core storage tank containing crude oil; and driving the crude oil in the first core storage tank or the second core storage tank to flow sequentially through a wellbore oil production simulation unit and a subsea gathering and transportation simulation unit.

[0021] In one possible implementation, activating the gas injection device and the water injection device includes: activating the gas injection device to inject gas into a first or second core storage tank containing crude oil, the gas driving the crude oil to flow sequentially through a wellbore oil production simulation unit and a subsea gathering and transportation simulation unit to simulate a gas-driven oil recovery method; or, activating the water injection device to inject liquid into a first or second core storage tank containing crude oil, the liquid driving the crude oil to flow sequentially through a wellbore oil production simulation unit and a subsea gathering and transportation simulation unit to simulate a water-driven oil recovery method.

[0022] In one possible implementation, after injecting gas or liquid into the first or second core storage tank containing crude oil, the method further includes: activating a gas injection device to inject gas into the wellbore oil production simulation unit, where the gas mixes with the crude oil entering the wellbore oil production simulation unit and flows to the underwater gathering and transportation simulation unit to simulate oil and gas two-phase flow; or, after injecting gas or liquid into the first or second core storage tank containing crude oil, the method further includes: activating a water injection device to inject liquid into the wellbore oil production simulation unit, where the liquid mixes with the crude oil entering the wellbore oil production simulation unit to simulate oil and gas two-phase flow. The crude oil entering the wellbore oil production simulation unit is mixed and flows to the underwater gathering and transportation simulation unit to simulate oil-water two-phase flow; or, after injecting gas or liquid into the first or second core storage tank containing crude oil, the process further includes: starting the gas injection device to inject gas into the wellbore oil production simulation unit; starting the water injection device to inject liquid into the wellbore oil production simulation unit; the gas and liquid in the wellbore oil production simulation unit are mixed with the crude oil entering the wellbore oil production simulation unit and flow to the underwater gathering and transportation simulation unit to simulate oil-gas-water three-phase flow.

[0023] In one possible implementation, a buffer tank is connected between the outlet of the underwater gathering and transportation simulation unit and the inlets of the first and second core oil storage tanks. The buffer tank is connected to a plunger pump. The experimental method includes: starting the gas injection device or water injection device to inject gas or liquid into the first core oil storage tank containing crude oil, pushing the crude oil to flow sequentially through the wellbore oil production simulation unit and the underwater gathering and transportation simulation unit; the plunger pump retracts, the piston in the buffer tank moves downward, and the crude oil flows into the buffer tank; when the crude oil in the first core oil storage tank is insufficient, the gas inlet or liquid inlet of the second core oil storage tank is opened, and the outlet of the second core oil storage tank is opened, while the gas inlet or liquid inlet of the first core oil storage tank is closed, and the first core oil storage tank is shut off. The crude oil in the second core reservoir flows sequentially through the wellbore production simulation unit and the underwater gathering and transportation simulation unit. The plunger pump pressurizes the oil, causing the piston in the buffer tank to move upwards, and the crude oil in the buffer tank is re-injected into the first core reservoir. When the crude oil in the second core reservoir is insufficient, the air inlet or liquid inlet of the first core reservoir is opened, and the liquid outlet of the first core reservoir is also opened. The air inlet or liquid inlet of the second core reservoir is closed, and the liquid outlet of the second core reservoir is also closed, causing the crude oil in the first core reservoir to flow sequentially through the wellbore production simulation unit and the underwater gathering and transportation simulation unit. The plunger pump retracts, and the piston in the buffer tank moves downwards, allowing the crude oil to flow into the buffer tank. This cycle repeats sequentially, simulating a pump-free shear cycle drive mode.

[0024] In one possible implementation, after the driving fluid flows sequentially through the wellbore oil production simulation unit and the underwater gathering and transportation simulation unit, the method further includes: extending a pressurized sampler into the fluid pipeline to obtain a fluid sample; or retracting the pressurized sampler outside the fluid pipeline to allow the fluid to flow normally.

[0025] This application provides an experimental apparatus and method for simulating long-distance transportation in deepwater oilfields. The experimental apparatus includes a formation displacement simulation unit, a wellbore production simulation unit, and a surface transportation simulation unit. The formation displacement simulation unit is equipped with a first core reservoir, a second core reservoir, a gas injection device, and a water injection device. The water inlets of both the first and second core reservoirs are connected to the water injection device and the gas injection device. The liquid outlets of the first and second core reservoirs are connected to the wellbore production simulation unit. The liquid outlet of the wellbore production simulation unit is connected to the liquid inlet of the subsea gathering and transportation simulation unit. The liquid outlet of the subsea gathering and transportation simulation unit is connected to the liquid inlets of the first and second core reservoirs. Both the wellbore production simulation unit and the subsea gathering and transportation simulation unit are equipped with retrievable pressurized samplers. This setup integrates formation oil recovery, wellbore production, and subsea gathering and transportation, overcoming the error accumulation problem caused by the independent setup of each part in traditional devices. It also solves the problem that wellbore production and surface gathering and transportation cannot accurately simulate initial conditions. In addition, the gas injection and water injection devices can simulate two production methods: gas injection and water injection. They can also simulate three pipeline flow states: oil-gas two-phase flow, oil-water two-phase flow, and oil-gas-water three-phase flow. During operation, two modes can be used: single-pressurization pump drive and pumpless shear circulation drive. This can realistically simulate the shear state of the fluid under the pump and pipeline, solving the problems of repeated shearing of the fluid by the circulating pump, damage to the internal structure of the fluid, and impact on flow parameters in traditional devices. Attached Figure Description

[0026] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0027] Figure 1 is a frame structure diagram of the experimental device for simulating long-distance transportation in deep-water oilfields provided in the embodiments of this application;

[0028] Figure 2 is a schematic diagram of the pressurized sampler in the experimental device for simulating long-distance transportation in deep-water oilfields provided in the embodiments of this application;

[0029] Figure 3 shows the state of the pressurized sampler taking samples in the experimental device for simulating long-distance transportation in deep-water oilfields provided in the embodiments of this application;

[0030] Figure 4 is a flowchart of the experimental method for simulating long-distance transportation in deep-water oilfields provided in the embodiments of this application.

[0031] Figure reference numerals: 1-Experimental apparatus simulating long-distance transportation in deepwater oilfields; 11-First needle valve; 12-Second needle valve; 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30-Ball valves; 100-Formation displacement simulation unit; 200-Wellbore production simulation unit; 300-Subsea gathering and transportation simulation unit; 400-Pressurized sampler; 500-Buffer tank; 600-Plunger pump; 700-Separator; 101-Core; 110-First core reservoir; 120-Second core reservoir; 130-Gas injection device; 140 - Water injection device; 220 - First plexiglass tube; 230 - First steel wire hose; 240 - Oil production tubing; 320 - Wellhead surface flow unit; 330 - Marine riser flow unit; 410 - Sampling pipeline; 420 - Drainage pipe; 430 - Drive assembly; 440 - Back pressure valve; 131 - Gas storage tank; 132 - Compressor; 141 - Water storage component; 142 - Heater; 143 - First water pump; 321-Second acrylic tube; 322-Gathering and transporting pipeline; 331-Ocean current simulation tank; 332-Second steel wire hose; 333-Third steel wire hose; 334-Riser; 335-Water flow control device; 336-Recovery bucket; 337-Third acrylic tube; 338-Platform pipeline; 339-Fourth acrylic tube; 411-First short pipe; 412-Pressurized sampling pipe; 413-Second short pipe; 431-Shell; 432-Fixed pipe; 433-Positioning piston; 434-Drive pump; 3351-Water storage component; 3352-Pumping assembly; 3353-Check valve; 33521-Pumping pipe; 33522-Second water pump; 33523-Flow meter; 33524-Check valve. Detailed Implementation

[0032] As described in the background section, deep-sea areas contain abundant oil, gas, and water resources, which can contribute significantly to economic development. However, the complex deep-sea environment makes development difficult and technically demanding, thus limiting the exploitation of deep-sea oil, gas, and water resources.

[0033] In view of this, this application provides an experimental device for simulating long-distance transportation in deepwater oilfields, including a formation displacement simulation unit, a wellbore production simulation unit, and a surface transportation simulation unit. The formation displacement simulation unit is equipped with a first core reservoir, a second core reservoir, a gas injection device, and a water injection device. The water inlets of both the first and second core reservoirs can be connected to the water injection device and the gas injection device. The liquid outlets of the first and second core reservoirs can be connected to the wellbore production simulation unit. The liquid outlet of the wellbore production simulation unit is connected to the liquid inlet of the subsea gathering and transportation simulation unit. The liquid outlet of the subsea gathering and transportation simulation unit is connected to the liquid inlets of the first and second core reservoirs. The wellbore production simulation unit and the subsea gathering and transportation simulation unit are also equipped with retrievable pressurized samplers. This configuration allows the three units to be interconnected via pipelines, integrating formation oil displacement, wellbore production, and surface gathering and transportation into one system. It overcomes the error accumulation problem caused by the independent setup of each part in traditional equipment and solves the challenge of accurately simulating initial conditions in wellbore production and surface gathering and transportation. Furthermore, the gas injection and water injection devices can simulate both gas-driven and water-driven oil extraction methods, and can simulate three flow states: oil-gas two-phase flow, oil-water two-phase flow, and oil-gas-water three-phase flow. During operation, two modes can be used: single-pump pressurization drive and pump-free shear circulation drive. This realistically simulates the shearing state of the fluid under the influence of the pump and pipeline, solving the problems of repeated shearing of the fluid by the circulating pump, damage to the internal structure of the fluid, and impact on flow parameters in traditional equipment.

[0034] To make the above-mentioned objectives, features, and advantages of the embodiments of this application more apparent and understandable, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of them. All other embodiments obtained by those skilled in the art based on the embodiments of this application without creative effort are within the scope of protection of this application.

[0035] Figure 1 is a structural diagram of the experimental apparatus for simulating long-distance transportation in deepwater oilfields provided in an embodiment of this application. Referring to Figure 1, this embodiment of the application provides an experimental apparatus for simulating long-distance transportation in deepwater oilfields (hereinafter referred to as the experimental apparatus). The experimental apparatus 1 can be used to study the flow characteristics of multiphase flow under ultra-long and complex deepwater paths. For example, it can be used to study the effects of different temperatures, pressures, ocean current velocities, seabed undulations, and other factors on the flow regime and pressure loss characteristics of multiphase fluids.

[0036] Experimental device 1 includes a formation oil displacement simulation unit 100, a wellbore oil production simulation unit 200, and a subsea gathering and transportation simulation unit 300, which can be used to simulate formation oil displacement, wellbore oil production, and surface gathering and transportation, respectively. The three units can be interconnected through pipelines, which may effectively avoid the problems of separate unit settings, increased interconnection errors, and inability to realistically simulate initial conditions for wellbore oil production and surface gathering and transportation in current traditional devices.

[0037] The formation oil displacement simulation unit 100 is equipped with a first core reservoir 110 and a second core reservoir 120, each containing a core 101. Since the underlying structure of each block is different, the arrangement of the cores 101 can be determined according to the actual formation structure. Compared to traditional devices that do not contain cores or only contain a single core, the experimental device provided in this embodiment can better simulate the undulating topography of the seabed, facilitating the simulation of fluid flow in real formations. Both the first core reservoir 110 and the second core reservoir 120 are equipped with multiple ball valves connected to pipes, allowing communication with other parts. The entry and exit of oil, gas, and water can be controlled by opening and closing the ball valves. The first core reservoir 110 and the second core reservoir 120 can also be interconnected.

[0038] In addition, the formation flooding simulation unit 100 also includes a gas injection device 130, which can be used to simulate the gas injection flooding extraction method. The gas injection device 130 includes a gas storage tank 131, and the gas outlet of the gas storage tank 131 is connected to the gas inlets of the first core oil storage device 110 and the second core oil storage device 120 through a pipeline. A needle valve can be installed on the gas outlet pipeline of the gas storage tank 131 to control the opening and closing of the gas path. Only one needle valve can be installed on the gas outlet pipeline of the gas storage tank 131. Alternatively, to obtain a more precise gas flow rate, multiple needle valves can be set in parallel. For example, two needle valves can be set in parallel, namely the first needle valve 11 and the second needle valve 12.

[0039] The gas injection device 130 also includes a gas storage tank 131 and a compressor 132. The gas storage tank 131 is used to store gas. In the simulation, the gas can be natural gas or other gases, and this application embodiment does not impose specific limitations on this. The compressor 132 is connected to the gas storage tank 131 and can apply pressure to the gas storage tank 131 to drive the gas in the gas storage tank 131 to be injected into the first core oil reservoir 110 or the second core oil reservoir 120.

[0040] Specifically, the gas injection oil displacement process is as follows: First, crude oil and core 101 are placed into the first core oil storage tank 110 or the second core oil storage tank 120. The compressor 132 is started to pressurize the gas storage tank 131 to the test pressure, causing the gas to pass through the first needle valve 11, the second needle valve 12, and the flow meter. Then, the gas enters the first core oil storage tank 110 and the second core oil storage tank 120 respectively through ball valves 13 and 16, causing the crude oil to flow out from ball valves 14 and 17 respectively, entering the wellbore oil production simulation unit 200.

[0041] The formation flooding simulation unit 100 also includes a water injection device 140, which can be used to simulate water-injection flooding extraction. The water injection device 140 is equipped with a water storage unit 141, and a first water pump 143 is installed on the outlet pipe of the water storage unit 141. The outlet pipe can be connected to a first core oil storage tank 110 and a second core oil storage tank 120, respectively. Furthermore, since crude oil has poor fluidity, the water storage unit 141 can also be connected to a heater 142, which heats the water before it is introduced into the oil storage tank. The water can transfer heat to the crude oil, improving its fluidity.

[0042] Specifically, the water injection oil displacement process is as follows: crude oil and core 101 are placed into the first core oil reservoir 110 and the second core oil reservoir 120. The heater 142 is started to heat the water in the water storage unit 141 to the test temperature. The first water pump 143 is turned on, allowing the water in the water reservoir to enter the first core oil reservoir 110 or the second core oil reservoir 120 through ball valve 20 or ball valve 24 respectively. By opening ball valves 21, 22, and 26, crude oil can be driven to flow out from ball valves 21 and 26 to the wellbore oil production simulation unit 200.

[0043] Furthermore, the pipeline in this embodiment includes multiple transparent pipe sections and flexible hoses. The transparent pipe sections allow for clear observation of the fluid flow pattern and internal flow state. The transparent pipe sections used in this embodiment are made of plexiglass, but other materials can also be used; this application does not impose specific limitations on this. The flexible hoses can adjust the angle of the pipeline and can be used to simulate pipeline flow in different seabed structural environments. For example, the flexible hose used in this application is a steel wire hose.

[0044] The wellbore oil production simulation unit 200 is equipped with a first plexiglass tube 220 and a first steel wire hose 230. The inlet of the wellhead oil production simulation unit can be connected to the outlet of the first core reservoir 110 and the outlet of the second core reservoir 120. After the crude oil flows out from the first core reservoir 110 or the second core reservoir 120, it enters the underwater gathering and transportation simulation unit 300 through the first plexiglass tube 220 and the first steel wire hose 230.

[0045] The surface gathering and transportation unit can be divided into a wellhead surface flow unit 320 and a marine riser flow unit 330. The inlet end of the wellhead surface flow unit 320 is connected to the outlet end of the wellbore oil production simulation unit 200. The wellhead surface flow unit 320 can be equipped with a second plexiglass tube 321 and a gathering and transportation pipeline 322. Crude oil enters the marine riser flow unit 330 through the second plexiglass tube 321 and the gathering and transportation pipeline 322.

[0046] The ocean riser flow unit 330 includes an ocean current simulation tank 331 erected vertically relative to the ground. A riser 334 is installed inside the ocean current simulation tank. The two ends of the riser 334 can be connected to the gathering and transportation pipeline 322 and the platform pipeline 338 respectively through a second steel wire hose 332 and a third steel wire hose 333. The use of steel wire hoses here allows the riser 334 to be oscillating along the height direction of the ocean current simulation tank 331, thus making the fluid flow smoother. At the same time, the influence of external ocean current forces on the flow state inside the pipeline is taken into account, which can more realistically simulate the impact of ocean currents on the riser 334.

[0047] A water flow control device 335 is also connected to one side of the ocean current simulation tank 331. This device can be used to inject water into the ocean current simulation tank 331 and regulate the water flow rate within the tank. The water flow control device 335 includes a water storage component 3351 and multiple pumping components 3352 arranged sequentially along the height of the ocean current simulation tank 331. The pumping components 3352 are connected between the water storage component 3351 and the ocean current simulation tank 331, and include a pumping pipe 33521 and a second water pump 33522, a flow meter 33523, and a check valve 33524 on the pumping pipe 33521. For example, during simulation, the second water pump 33522, the ball valve, and the check valve 33524 are first activated to pump water from the water storage component 3351 into the ocean current simulation tank 331, and then the water flows into the recovery tank 336 through the check valve 3353.

[0048] The system can activate pumping units 3352 at different heights according to the water flow rate at different heights. These units can be activated individually, or simultaneously, with one unit at a certain height and another below it, to improve water injection efficiency. This allows for the simulation of the impact and swaying of the riser 334 caused by different water flow rates at different heights. Furthermore, multiple pressure gauges and temperature gauges can be installed on the pipeline to monitor fluid pressure and temperature data.

[0049] It should be noted that the water storage component 3351 can be set separately, or, when the capacity of the water storage component is large enough, the water storage component 3351 and the water storage component 141 can be combined into one. This application embodiment does not impose specific restrictions on this.

[0050] At the outlet of the underwater gathering and transportation simulation unit 300, a separator 700, a buffer tank 500, and a plunger pump 600 are also connected. The plunger pump 600 is connected between the buffer tank 500 and a pressure source, which is the water storage device 3351. Alternatively, a separate pressure source can be provided for the buffer tank 500, such as a pneumatic or hydraulic pressure source. After testing, crude oil flows into the separator 700. When the ball valve 18 is opened, the plunger pump 600 retracts, causing the piston inside the buffer tank 500 to move downwards, and the crude oil in the separator 700 flows into the buffer tank 500.

[0051] The live sampler 400 can collect fluid from the fluid pipeline for analysis and research. When sampling is not needed, the live sampler can be retrieved without affecting the flow of fluid. Both the wellbore oil production simulation unit 200 and the subsea gathering and transportation simulation unit 300 are equipped with retrievable live samplers 400.

[0052] Figure 2 is a schematic diagram of the pressurized sampler in the experimental device for simulating long-distance transportation in deep-water oilfields provided in the embodiment of this application; Figure 3 is the state of the pressurized sampler during sampling in the experimental device for simulating long-distance transportation in deep-water oilfields provided in the embodiment of this application.

[0053] Referring to Figures 2 and 3, the pressurized sampler 400 is equipped with a drive assembly 430, which includes a housing 431, a fixed tube 432, a positioning piston 433, and a drive pump 434. The housing 431 is connected to a fluid pipeline. One end of the fixed tube 432 is located inside the housing 431, and the other end extends outside the housing 431 and connects to the sampling pipeline 410. The positioning piston 433 is movably disposed between the fixed tube 432 and the housing 431, and together with the fixed tube 432 and the housing 431, forms a fluid cavity with a variable volume. The fluid cavity can be a hydraulic cavity or a pneumatic cavity; this embodiment does not impose specific limitations on this. The drive pump 434 communicates with the fluid cavity and is used to drive the positioning piston 433 to move. For example, the drive pump 434 can be a manual pump or an electric pump.

[0054] In addition, the pressurized sampler 400 also includes a sampling pipeline 410. The inlet end of the sampling pipeline 410 is detachably connected to a fluid pipeline, and the outlet end of the sampling pipeline 410 is equipped with a back pressure valve 440, which can be used to adjust the pressure inside the sampling pipeline 410. It should be noted that all pipelines used to transport fluids in the wellbore oil production simulation unit 200 and the subsea gathering and transportation simulation unit 300 can be considered as fluid pipelines.

[0055] The sampling pipeline 410 includes a first short pipe 411, a pressurized sampling pipe 412, and a second short pipe 413 connected in sequence via ball valves. One end of the first short pipe is connected to the drive assembly 430 via a ball valve 27. The ball valve 27 can be used to seal and fix the pipe 432. The ball valves 28 and 29 can seal and disassemble the pressurized sampling pipe. The pressurized sampling pipe is used to hold the sampled fluid. After sampling is completed, the ball valves 28 and 29 are opened to remove the fluid in the pressurized sampling pipe for further study.

[0056] In addition, the inlet end of the sampling line 410 is connected to a drainage tube 420, which is connected to the positioning piston 433 and can communicate with the fixed tube 432. The drainage tube 420 can move radially along the fluid pipeline. By driving the pump 434 to pressurize or depressurize the fluid chamber, the position of the drainage tube 420 can be controlled, thereby obtaining fluid samples at different locations.

[0057] It should be noted that, compared to traditional devices where the sampling tube needs to extend all the way into the center of the pipe, altering the fluid flow pattern and interfering with the fluid flow state, and traditional sampling devices cannot change the sampling position, thus only obtaining fluid samples from a fixed location, the pressurized sampler 400 provided in this application embodiment, when sampling is not required, as shown in FIG3, allows the drainage tube 420 to retract into the housing 431, thereby not interfering with the fluid flow state within the pipe. Furthermore, by controlling the pressure within the fluid chamber through the driving pump 434, the position of the movable drainage tube 420 can be controlled, thereby obtaining fluid samples from different locations.

[0058] Specifically, referring to Figure 3, when the pressurized sampler 400 takes samples, it first controls the drive pump 434 to pressurize the fluid chamber, causing the positioning piston 433 to move to the left, and simultaneously driving the drainage tube 420 to move to the left. The back pressure valve is set, and ball valves 27, 28, and 29 are opened. The fluid in the pipeline flows outward sequentially through the first short tube 411, the pressurized sampling tube 412, the second short tube 413, and the back pressure valve 440. After the fluid flow stabilizes, ball valves 27, 28, and 29 are closed, and ball valves 28 and 29 are disassembled from the pressurized sampling tube 412 to obtain a pressurized fluid sample. The pressurized sampler 400 provided in this embodiment adopts an upstream sampling method. The sampling position can be adjusted by controlling the position of the drainage tube 420 to obtain the real-time status of the fluid at different locations. When not sampling, the sampling device can be withdrawn, avoiding interference with the fluid flow.

[0059] This application also provides an experimental method for simulating long-distance transportation in deepwater oilfields. Figure 4 is a flowchart of the steps of the experimental method for simulating long-distance transportation in deepwater oilfields provided in this application. Referring to Figure 4, the experimental method includes the following steps:

[0060] S100. Put the crude oil into the first core reservoir or the second core reservoir.

[0061] During the simulation, crude oil is first placed into either the first core reservoir 110 or the second core reservoir 120. Cores 101 are arranged in either the first core reservoir 110 or the second core reservoir 120 to simulate the actual flow of crude oil in deep water. Cores 101 can be fixed in the core reservoir. Alternatively, to adapt to different terrains, cores 101 can be detachably installed in the core reservoir, and their arrangement can be adjusted according to different terrains.

[0062] S200. Start the gas injection device or water injection device to inject gas or liquid into the first or second core oil storage tank containing crude oil.

[0063] After being driven, the crude oil in S300, the first core storage tank or the second core storage tank flows sequentially through the wellbore oil production simulation unit and the underwater gathering and transportation simulation unit.

[0064] In one possible implementation, only the gas injection device is activated. Specifically, compressor 132 is activated to pressurize gas storage tank 131 to the test pressure, causing gas to pass through first needle valve 11, second needle valve 12, and flow meter, and then through ball valve 13 into first core oil reservoir 110. The gas pushes crude oil out of ball valve 14 and sequentially flows through wellbore oil production simulation unit 200 and subsea gathering and transportation simulation unit 300 to simulate gas-driven oil extraction. Alternatively, compressor 132 is activated to pressurize gas storage tank 131 to the test pressure, causing gas to pass through first needle valve 11, second needle valve 12, and flow meter, and then through ball valve 16 into second core oil reservoir 120. The gas pushes crude oil out of ball valve 17 and sequentially flows through wellbore oil production simulation unit 200 and subsea gathering and transportation simulation unit 300 to simulate gas-driven oil extraction.

[0065] It should be noted that the first core reservoir 110 or the second core reservoir 120 can be started during the drive. The following simulation method will take the start of the first core reservoir 110 as an example.

[0066] In another possible implementation, only the water injection device is activated. Specifically, heater 142 is activated to heat the water in water storage unit 141 to the test temperature. The first water pump 143 is turned on, allowing water in the water storage tank to enter the first core oil storage tank 110 through ball valve 20. Ball valves 21 and 22 are opened, allowing the liquid to drive crude oil to flow out from ball valve 21 and sequentially through the wellbore oil production simulation unit 200 and the subsea gathering and transportation simulation unit 300 to simulate the gas injection oil recovery method.

[0067] In addition, this experimental device can simulate three pipe flow states—oil-gas two-phase flow, oil-water two-phase flow, and oil-gas-water three-phase flow—under two different extraction methods: gas injection and water injection.

[0068] Specifically, crude oil is placed into the first core storage tank 110, and the compressor 132 is started to pressurize the gas storage tank 131 to the test pressure. The gas is injected into the oil production cylinder 240 through the first needle valve 11, the second needle valve 12, and the ball valve 30. The heater 142 is started to heat the water in the water storage unit 141 to the test temperature. Then, the first water pump 143 is started to pump the water in the water storage unit 141 into the first core storage tank 110 through the ball valve 20, which drives the crude oil in the first core storage tank 110 to flow into the oil production cylinder 240 through the ball valves 21 and 22 in sequence. Crude oil is mixed with gas entering the oil production tank 240 and flows sequentially through the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the fourth plexiglass tube 339 for testing, thereby realizing two-phase flow of oil and gas.

[0069] Crude oil is placed into the first core reservoir 110. Heater 142 is started, which heats the water in water storage unit 141 to the test temperature. Then, the first water pump 143 is started, and the water in water storage unit 141 is injected into the oil production tank 240 through ball valve 23. Compressor 132 is started, and the gas storage tank 131 is pressurized to the test pressure. The gas enters the first core reservoir 110 through the first needle valve 11, the second needle valve 12, and the ball valve 13. The crude oil in the first core reservoir 110 flows into the oil production tank 240 through ball valves 14 and 15 in sequence. Crude oil is mixed with the liquid entering the oil production tank 240 and flows sequentially through the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the fourth plexiglass tube 339 for testing, thereby realizing oil-water two-phase flow.

[0070] Crude oil is placed into the first core reservoir 110. Compressor 132 is started to pressurize the gas tank 131 to the test pressure. Gas enters the first core reservoir 110 through the first needle valve 11, the second needle valve 12, and the ball valve 13, driving the crude oil in the first core reservoir 110 to flow sequentially into the oil production cylinder 240 through ball valves 14 and 15. Simultaneously, gas is injected into the oil production cylinder 240 through the first needle valve 11, the second needle valve 12, and the ball valve 30. Heater 142 is started to heat the water in the water storage unit 141 to the test temperature. Then, the first water pump 143 is started, and the water in the water storage unit 141 is injected into the oil production cylinder 240 through the ball valve 23. The gas and liquid inside the oil production tank 240 are mixed with the crude oil entering the oil production tank 240, and then flow through the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the fourth plexiglass tube 339 for testing, thereby realizing the three-phase flow of oil, gas and water.

[0071] Furthermore, in current conventional devices, the repeated shearing of the fluid by the circulating pump can easily damage the internal structure of the fluid, thereby affecting flow parameters. Therefore, the experimental device provided in this application embodiment can simulate both pump-driven single-pressurization and pump-free shearing cyclic drive modes.

[0072] Specifically, in one embodiment, crude oil is placed in the first core oil storage tank 110, and the compressor 132 is started to pressurize the gas storage tank 131 to the test pressure. Gas is injected into the first core oil storage tank 110 through needle valve 1, needle valve 2, and ball valve 13, driving the crude oil in the first core oil storage tank 110 to flow sequentially through ball valve 14 and ball valve 15 into the oil production tank 240, the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the plexiglass tube 339 for testing. Multiple flow meters, thermometers, and pressure gauges can be installed along the line to test the flow rate, temperature, and pressure of the fluid, thereby completing the single-cycle pressurization drive of the pump driven by gas injection.

[0073] In another embodiment, crude oil is placed in the first core oil storage tank 110, and the heater 142 is started. The heater 142 heats the water in the water storage unit 141 to the test temperature. The first water pump 143 is started, and the water in the water storage unit 141 is injected into the first core oil storage tank 110 through the ball valve 20. Since the density of water is greater than that of crude oil, the water will drive the crude oil to flow out through the ball valves 21 and 22, and then flow sequentially into the oil production tank 240, the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the fourth plexiglass tube 339 for testing. This completes the single-time pressurization drive of the pump driven by water injection.

[0074] In addition, taking gas injection as an example, crude oil is injected into the first core oil storage tank 110 and the second core oil storage tank 120. The compressor 132 is started to pressurize the gas storage tank 131 to the test pressure. The gas is injected into the first core oil storage tank 110 through needle valve 1, needle valve 2 and ball valve 13. The crude oil in the first core oil storage tank 110 is driven to flow into the oil production tank 240, the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338 and the fourth plexiglass tube 339 for testing. After testing, the crude oil flows into the separator 700. The ball valve 18 is opened and the plunger pump 600 is retracted, causing the piston in the buffer tank 500 to move down. The crude oil in the separator 700 flows into the buffer tank 500.

[0075] When the crude oil in the first core reservoir 110 is about to run out, ball valves 16 and 17 are opened, and ball valves 13 and 14 are closed. The crude oil in the second core reservoir 120 flows into the oil production tank 240 through ball valves 17 and 15, and then passes through the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering and transportation pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the fourth plexiglass tube 339 for testing. After the test, the crude oil flows into the separator 700.

[0076] At this point, ball valve 18 is closed, and plunger pump 600 pressurizes and drives the piston in buffer tank 500 upward, thereby re-injecting the crude oil in buffer tank 500 into the first core reservoir 110 through ball valve 19. When the crude oil in the second core reservoir 120 is about to run out, ball valves 13 and 14 are opened, and ball valves 16 and 17 are closed, allowing the crude oil in the first core reservoir 110 to be driven back into the test. This cycle is repeated sequentially, achieving pump-free shear cycle drive.

[0077] Similarly, the pumpless shear cycle drive can initially be driven by water injection. In this case, crude oil is injected into the first core reservoir 110 and the second core reservoir 120, and the heater 142 is started. The heater 142 heats the water in the water storage unit 141 to the test temperature. The first water pump 143 is started, and the water in the water storage unit 141 is injected into the first core reservoir 110 through the ball valve 20. Crude oil flows sequentially into the oil production tank 240 and the first plexiglass through the ball valves 21 and 22. Pipe 220, first steel wire hose 230, second plexiglass pipe 321, gathering and transportation pipeline 322, second steel wire hose 332, riser 334, third plexiglass pipe 337, third steel wire hose 333, platform pipeline 338, and plexiglass pipe 339 are tested. After the test, the crude oil flows into the separator 700. The ball valve 18 is opened, the plunger pump 600 is retracted, causing the piston in the buffer tank 500 to move down, and the crude oil in the separator 700 flows into the buffer tank 500. When the crude oil in the first core reservoir 110 is about to run out, open ball valves 24 and 26, and close ball valves 20 and 21. At this time, the crude oil in the second core reservoir 120 flows through ball valves 26 and 22 into the oil production tank 240, the first plexiglass tube 220, the first steel wire hose 230, the second plexiglass tube 321, the gathering pipeline 322, the second steel wire hose 332, the riser 334, the third plexiglass tube 337, the third steel wire hose 333, the platform pipeline 338, and the fourth plexiglass tube 339 for testing. After the test, the crude oil flows into the separator 700. At this time, close ball valve 18, and the plunger pump 600 pressurizes and drives the piston in the buffer tank 500 to move upward, thereby injecting the crude oil in the buffer tank 500 back into the first core reservoir 110 through ball valve 19. When the crude oil in the second core reservoir 120 is about to run out, ball valves 20 and 21 are opened, and ball valves 24 and 26 are closed. The crude oil in the first core reservoir 110 is then driven back into the test, and this cycle repeats.

[0078] It should be noted that the terms "one embodiment," "embodiment," "exemplary embodiment," "some embodiments," etc., mentioned in the specification indicate that the described embodiment may include a specific feature, structure, or characteristic, but not every embodiment necessarily includes that specific feature, structure, or characteristic. Furthermore, such phrases do not necessarily refer to the same embodiment. Moreover, when a specific feature, structure, or characteristic is described in connection with an embodiment, implementing such a feature, structure, or characteristic in conjunction with other embodiments, whether explicitly described or not, is within the knowledge scope of those skilled in the art.

[0079] Generally speaking, terms should be understood at least in part by their use in context. For example, at least in part by context, the term "one or more" as used in the text can be used to describe any feature, structure, or characteristic of the singular meaning, or a combination of features, structures, or characteristics of the plural meaning. Similarly, at least in part by context, terms such as "a" or "the" can also be understood to convey either singular or plural usage.

[0080] It should be readily understood that the terms “on,” “above,” and “on top of” in this application should be interpreted in the broadest possible sense, such that “on” means not only “directly on something” but also “on something” with an intermediate feature or layer therebetween, and that “above” or “on top of” means not only “on top of something” but also “on top of something” without an intermediate feature or layer therebetween (i.e., directly on something).

[0081] Furthermore, for ease of explanation, spatially relative terms such as "below," "below," "under," "above," and "above" may be used to describe the relationship of one element or feature relative to other elements or features as shown in the figures. Spatially relative terms are intended to encompass different orientations of the device in use or operation other than those shown in the figures. The device may have other orientations (rotated 90° or in other orientations), and the spatially relative descriptive terms used herein may be interpreted accordingly.

[0082] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features therein. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of this application.

Claims

1. An experimental apparatus for simulating long-distance transportation in deep-water oilfields, characterized in that, include: The formation oil displacement simulation unit (100) includes a first core oil reservoir (110), a second core oil reservoir (120), an injection gas device (130), and a water injection device (140); the air inlet of the first core oil reservoir (110) and the air inlet of the second core oil reservoir (120) are both connected to the injection gas device (130), the water inlet of the first core oil reservoir (110) and the water inlet of the second core oil reservoir (120) are both connected to the water injection device (140), and the first core oil reservoir (110) and the second core oil reservoir (120) are interconnected; A wellbore oil production simulation unit (200) is provided, wherein the inlet end of the wellbore oil production simulation unit (200) is connected to the outlet of the first core oil reservoir (110) and the outlet of the second core oil reservoir (120), and the gas injection device (130) and the water injection device (140) are both connected to the wellbore oil production simulation unit (200). The underwater gathering and transportation simulation unit (300) has its inlet end connected to the outlet end of the wellbore oil production simulation unit (200), and its outlet end connected to the inlet of the first core oil storage device (110) and the inlet of the second core oil storage device (120).

2. The experimental apparatus according to claim 1, characterized in that, Both the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300) are equipped with a retractable pressurized sampler (400), which can extend into the fluid pipeline or be retracted to the outside of the fluid pipeline.

3. The experimental apparatus according to claim 1, characterized in that, The underwater gathering and transportation simulation unit (300) includes: Wellhead surface flow unit (320), the inlet end of which is connected to the outlet end of the wellbore oil production simulation unit (200); The marine riser flow unit (330) has its inlet end connected to the outlet end of the wellhead surface flow unit (320), and its outlet end is connected to the inlet of the first core reservoir (110) and the inlet of the second core reservoir (120).

4. The experimental apparatus according to claim 3, characterized in that, The marine riser flow unit (330) includes: Ocean current simulation tank (331); A riser (334) is installed inside the ocean current simulation tank (331) and is oscillatingly arranged along the height direction of the ocean current simulation tank (331); the inlet end of the riser (334) is connected to the outlet end of the wellhead surface flow unit (320), and the outlet end of the riser (334) is connected to the inlet of the first core oil reservoir (110) and the inlet of the second core oil reservoir (120); A water flow control device (335) is connected to the ocean current simulation tank (331) and is used to inject water into the ocean current simulation tank (331) and adjust the water flow rate in the ocean current simulation tank (331).

5. The experimental apparatus according to claim 4, characterized in that, The water flow control device (335) includes: Water storage component (3351); Multiple pumping components (3352) are provided, each of which is connected between the water storage unit (3351) and the ocean current simulation tank (331), and each of the pumping components (3352) is arranged sequentially along the height direction of the ocean current simulation tank (331).

6. The experimental apparatus according to claim 5, characterized in that, The pumping assembly (3352) includes a pumping pipe connected between the water storage unit (3351) and the ocean current simulation tank (331), as well as a water pump, a flow meter and a one-way valve installed on the pumping pipe.

7. The experimental setup of claim 4, wherein, Both sides of the ocean current simulation tank (331) in the height direction are provided with flexible hoses, and the liquid inlet end and the liquid outlet end of the riser (334) are connected to the flexible hoses.

8. The experimental apparatus according to any one of claims 1-7, characterized in that, The pressurized sampler (400) includes: The sampling pipeline (410) has its inlet end detachably connected to a fluid pipeline and its outlet end equipped with a back pressure valve. The drainage tube (420) is connected to the inlet end of the sampling tube (410) and can move radially along the fluid pipe; A drive assembly (430) is connected between the fluid conduit and the inlet end of the sampling conduit (410) for driving the drainage tube (420) to move.

9. The experimental setup of claim 8, wherein, The sampling pipeline (410) includes a first short pipe (411), a pressurized sampling pipe and a second short pipe (413) connected in sequence by a ball valve. The other end of the first short pipe (411) is connected to the drive assembly (430) through a ball valve, and the back pressure valve is connected to the other end of the second short pipe (413).

10. The experimental setup of claim 8, wherein, The drive component (430) includes: A housing (431) is connected to the fluid conduit; A fixed tube (432) is provided, one end of which is located inside the housing (431), and the other end of which extends outside the housing (431) and is connected to the sampling pipeline (410). The positioning piston (433) is movably disposed between the fixed tube (432) and the housing (431), and together with the fixed tube (432) and the housing (431) form a fluid cavity with variable volume; A drive pump (434) is connected to the fluid cavity and is used to drive the positioning piston (433) to move; The drainage tube (420) is connected to the positioning piston (433) and communicates with the fixing tube (432).

11. The experimental apparatus according to any one of claims 1-7, characterized in that, Also includes: A buffer tank (500) is connected between the liquid outlet of the underwater gathering and transportation simulation unit (300) and the liquid inlet of the first core oil storage tank (110) and the liquid inlet of the second core oil storage tank (120). A plunger pump (600) is connected between the buffer tank (500) and the water storage unit (3351).

12. The experimental setup of claim 11, wherein, Also includes: A separator (700) is connected between the liquid outlet of the underwater gathering and transportation simulation unit (300) and the buffer tank (500).

13. The experimental setup of any one of claims 1-7, wherein, The fluid pipelines of the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300) are equipped with multiple transparent pipe sections.

14. An experimental method for simulating long-distance transportation in deep-water oilfields, applied to the experimental apparatus described in any one of claims 1-13, characterized in that, The experimental methods include: The crude oil is placed into the first core reservoir (110) or the second core reservoir (120); Start the gas injection device (130) or water injection device (140) to inject gas or liquid into the first core oil reservoir (110) or the second core oil reservoir (120) containing crude oil; After the crude oil in the first core storage tank (110) or the second core storage tank (120) is driven, it flows sequentially through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300).

15. The experimental method of claim 14, wherein, The gas injection device (130) or water injection device (140) includes: The gas injection device (130) is activated to inject gas into the first core oil storage tank (110) or the second core oil storage tank (120) containing crude oil. The gas pushes the crude oil to flow sequentially through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300) to simulate the gas injection oil recovery method. Alternatively, the water injection device (140) can be activated to inject liquid into the first core oil storage tank (110) or the second core oil storage tank (120) containing crude oil. The liquid will push the crude oil to flow sequentially through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300) to simulate the water injection oil recovery method.

16. The experimental method of claim 14, wherein, After injecting gas or liquid into the first core reservoir (110) or the second core reservoir (120) containing crude oil, the process further includes: The gas injection device (130) is activated to inject gas into the wellbore oil production simulation unit (200). The gas mixes with the crude oil entering the wellbore oil production simulation unit (200) and flows to the underwater gathering and transportation simulation unit (300) to simulate oil and gas two-phase flow. Alternatively, after injecting gas or liquid into the first core reservoir (110) or the second core reservoir (120) containing crude oil, the method further includes: The water injection device (140) is activated to inject liquid into the wellbore oil production simulation unit. The liquid mixes with the crude oil entering the wellbore oil production simulation unit (200) and flows to the underwater gathering and transportation simulation unit (300) to simulate oil-water two-phase flow. Alternatively, after injecting gas or liquid into the first core reservoir (110) or the second core reservoir (120) containing crude oil, the process further includes: Start the gas injection device (130) to inject gas into the wellbore oil production simulation unit (200); Start the water injection device (140) to inject liquid into the wellbore oil production simulation unit (200); The gas and liquid in the wellbore oil production simulation unit (200) are mixed with the crude oil entering the wellbore oil production simulation unit (200) and flow to the underwater gathering and transportation simulation unit (300) to simulate the three-phase flow of oil, gas and water.

17. The experimental method of claim 14, wherein, A buffer tank (500) is connected between the liquid outlet of the underwater gathering and transportation simulation unit (300), the liquid inlet of the first core oil storage tank (110), and the liquid inlet of the second core oil storage tank (120). The buffer tank (500) is connected to a plunger pump (600). The experimental methods include: Start the gas injection device (130) or the water injection device (140) to inject gas or liquid into the first core oil storage tank (110) containing crude oil, and push the crude oil to flow through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300) in sequence. When the plunger pump (600) retracts, the piston inside the buffer tank (500) moves downward, and crude oil flows into the buffer tank (500); When the crude oil in the first core oil reservoir (110) is insufficient, the air inlet or liquid inlet of the second core oil reservoir (120) is opened and the liquid outlet of the second core oil reservoir (120) is opened, while the air inlet or liquid inlet of the first core oil reservoir (110) and the liquid outlet of the first core oil reservoir (110) are closed, so that the crude oil in the second core oil reservoir (120) flows sequentially through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300); The plunger pump (600) pressurizes the oil, the piston in the buffer tank (500) moves upward, and the crude oil in the buffer tank (500) is re-injected into the first core oil reservoir (110); When the crude oil in the second core oil reservoir (120) is insufficient, the air inlet or liquid inlet of the first core oil reservoir (110) is opened and the liquid outlet of the first core oil reservoir (110) is opened, and the air inlet or liquid inlet of the second core oil reservoir (120) is closed and the liquid outlet of the second core oil reservoir (120) is closed, so that the crude oil in the first core oil reservoir (110) flows sequentially through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300); When the plunger pump (600) retracts, the piston in the buffer tank (500) moves downward, and crude oil flows into the buffer tank (500); this cycle repeats, simulating a pump-free shear cycle drive mode.

18. The experimental method according to claims 14-17, characterized in that, After the driving fluid flows sequentially through the wellbore oil production simulation unit (200) and the underwater gathering and transportation simulation unit (300), the process further includes: extending a pressurized sampler (400) into the fluid pipeline to obtain a fluid sample; or retracting the pressurized sampler (400) outside the fluid pipeline to allow the fluid to flow normally.

Images