A multi-section visual gas injection oil displacement experiment device and method for simulating green electricity fluctuation

Abstract

The present application relates to oil and gas field development experimental equipment technical field, specifically relates to a kind of simulation green electricity fluctuation multi-section visual gas injection oil displacement experimental device and method.The experimental device includes reservoir reservoir cavity, injection-production integrated wellbore and reserved production wellbore being arranged in the inner cavity of reservoir reservoir cavity, steam generator being arranged in the gas injection end of injection-production integrated wellbore, condensing recovery tank being arranged in the exhaust end of injection-production integrated wellbore, the inner cavity of two-section injection-production integrated wellbore is provided with axially movable electric heating rod, for heating fluid in injection-production integrated wellbore, the power of control unit and axial movement position are adjusted according to the data of thermocouple and pressure gauge collected, the power input end of control unit is connected green electricity simulation unit.The renewable energy driven experiment is realized by introducing green electricity energy supply into thermal recovery experimental system.Multiple-section wellbore electric heating can dynamically compensate heat loss, improve steam dryness and displacement efficiency.The same device can complete huff and puff, steam drive and SAGD experiment, and experimental cost is greatly reduced.

Description

Technical Field

[0001] This invention relates to the field of experimental equipment technology for oil and gas field development, specifically to a multi-stage visualized gas injection and oil displacement experimental device and method for simulating green electricity fluctuations, and more particularly to a laboratory-grade multi-stage gas injection and oil displacement experimental device capable of simulating green electricity fluctuations, realizing intermittent heating, multi-process switching and visualized monitoring. Background Technology

[0002] Heavy oil resources occupy an important position in the global oil and gas resource structure. Steam injection and steam drive, as the most mature thermal recovery technologies, reduce crude oil viscosity by injecting high-temperature, high-pressure steam into the reservoir and have been widely used both domestically and internationally. The effectiveness of steam injection thermal recovery is subject to many factors, including steam temperature, dryness, injection rate, wellbore structure (vertical / horizontal well, perforated / open-hole completion), and reservoir heterogeneity. Simulating the steam injection thermal recovery process under laboratory conditions is an important means to optimize field injection and production parameters and reveal the heat and mass transfer mechanism. Existing reservoir simulation experimental devices typically consist of a one-dimensional or two-dimensional physical model, a constant-temperature heating system, a fluid injection system, and a data acquisition system. These devices can reproduce the temperature field changes and displacement efficiency during steam injection to a certain extent. However, with the transformation of the energy structure and the advancement of the "dual carbon" goal, the use of fluctuating electricity generated from renewable energy sources such as wind and solar power to directly power electrically heated steam generators has become a new trend in energy conservation and carbon reduction in oil and gas fields, posing new challenges to traditional reservoir simulation experimental devices.

[0003] First, existing devices struggle to simulate the impact of fluctuating green electricity on the heat injection process. Traditional experimental setups typically assume a stable power supply, employing constant power or PID temperature control for the heating system, making them incapable of responding to fluctuations in the external power grid. In real-world scenarios, the intermittency and volatility of green electricity lead to real-time variations in heating power, resulting in discontinuous "intermittent steam injection" conditions. Currently, there is a lack of experimental devices capable of receiving green electricity signals in real time and automatically adjusting heating power based on power fluctuations, causing a disconnect between laboratory research and actual field conditions. Second, existing devices face bottlenecks in visualizing steam flow patterns. The flow state of steam in the wellbore and near-wellbore zone directly affects the efficiency of heat transfer to the reservoir. However, high-temperature and high-pressure experimental environments (e.g., 300℃, 5 MPa) place stringent requirements on the material and sealing of the visualization window, forcing most devices to abandon direct observation and rely solely on indirect calculations of flow patterns through inlet and outlet parameters. While a few devices have designed visualization windows, these typically only withstand extremely low pressures, making them ineffective for integration with high-temperature and high-pressure steam injection systems. Furthermore, the lack of variable-diameter connection schemes for different pipe diameters limits the implementation of low-pressure visualization experiments. Furthermore, existing simulation devices have a simple wellbore structure, making it difficult to cover complex completion and well placement methods. In actual oilfield development, a combination of vertical and horizontal wells is often used, with perforated or open-hole completions selected based on formation characteristics. However, most existing reservoir simulators typically only pre-install injection and production wells in a single direction and often ignore the influence of perforation orifices on steam injection patterns, resulting in simulation results that cannot accurately reflect the injection dynamics and production patterns under different well types and completion methods. In addition, the heating positions of existing devices are fixed and cannot be dynamically adjusted according to changes in the reservoir temperature field. Fixed heat sources can easily lead to localized overheating or heating blind spots, making it difficult to simulate the impact of changes in heat source location on reservoir development performance under actual operating conditions.

[0004] For example, Chinese patent application 2019108799640, publication number CN110598340A, discloses "A method and apparatus for determining the experimental fluid for gas-driven oil displacement". The method includes: establishing a PVT model based on the actual reservoir fluid properties; calculating the oil-gas miscibility index λ reservoir based on the formation pressure P reservoir and the minimum miscibility pressure PMMP- reservoir of the injected gas and formation crude oil under actual reservoir conditions; calculating the gas injection gravity number η reservoir based on the density and viscosity differences between the formation crude oil and the injected gas under actual reservoir conditions; adjusting the composition of the simulated oil and injected gas in the experiment based on the composition of the formation crude oil and injected gas under actual reservoir conditions and the PVT model, with the goal of making the oil-gas miscibility index λ experiment and the gas injection gravity number η experiment under experimental conditions similar to those of the λ reservoir and η reservoir; and configuring the experimental fluid based on the adjusted composition of the simulated oil and injected gas.

[0005] Because existing technologies cannot simulate heating control driven by green electricity fluctuations, lack experimental methods that can simultaneously handle high-temperature injection and low-pressure visualization, have insufficient simulation capabilities for multiple well types, and have non-adjustable heating positions, the understanding of the complex mechanisms of steam injection thermal recovery under the new energy background is unclear. Therefore, there is an urgent need to develop a reservoir experimental device that can simulate green electricity driving, has visualization capabilities, can adapt to changes in multiple well types and completion methods, and has an adjustable heating position. Summary of the Invention

[0006] The purpose of this invention is to provide a multi-stage visualized gas injection-driven oil recovery experimental device and method for simulating green electricity fluctuations. By simulating heating control driven by green electricity fluctuations, the working mechanism of steam injection thermal recovery under the background of new energy is explored. At the same time, the visualization capability of the experimental device is improved, making it easier to directly observe the two-phase flow and condensation behavior during the operation of the experimental device.

[0007] The multi-stage visualized gas injection-driven oil recovery experimental device for simulating green electricity fluctuations, as described in this invention, includes an oil reservoir cavity, an integrated injection-production wellbore and a reserved production wellbore disposed within the cavity of the oil reservoir cavity, a steam generator disposed at the gas injection end of the integrated injection-production wellbore, and a condensate recovery tank disposed at the exhaust end of the integrated injection-production wellbore. The inner wall of the oil reservoir cavity is equipped with thermocouples for temperature detection, and the outer wall of the oil reservoir cavity is equipped with a reservoir cavity pressure gauge and a wellbore pressure gauge. The reservoir cavity pressure gauge is used to detect the pressure within the oil reservoir cavity. The pressure inside the wellbore is measured by a pressure gauge. The wellbore pressure gauge is used to detect the pressure inside the integrated injection-production wellbore. The wellbore is characterized by having an axially movable electric heating rod installed within its inner cavity. This electric heating rod is used to heat the fluid inside the wellbore. The power supply end of the electric heating rod is connected to the output end of a control unit. The signal acquisition end of the control unit is connected to a thermocouple, a reservoir cavity pressure gauge, and a wellbore pressure gauge. The power input end of the control unit is connected to a green electricity simulation unit. The control unit adjusts the power and axial movement position of the electric heating rod based on the data collected by the thermocouple and pressure gauge.

[0008] Preferably, the reservoir cavity includes a front cavity and a rear cavity arranged in series, and a connecting well section arranged between the front cavity and the rear cavity. The two ends of the connecting well section are respectively connected to the injection-production wellbore in the front cavity and the rear cavity. A visualization window is provided on the side wall of the connecting well section. The visualization window is used to observe the fluid flow state in the injection-production wellbore.

[0009] Preferably, the electric heating rod is fixedly mounted on the slider, the slider is slidably mounted on the slide rod, the slide rod is parallel to the axis of the injection-production wellbore and both ends of the slide rod are fixedly connected to the injection-production wellbore, a rotatable screw is provided in the inner cavity of the injection-production wellbore, the screw is parallel to the slide rod, the slider is threadedly connected to the screw, and one end of the screw passes through the end cover of the injection-production wellbore and is connected to the drive mechanism for transmission.

[0010] Preferably, the front and rear sections of the reservoir cavity are both cylindrical tanks with end caps at both ends, the integrated injection-production wellbore is located on the central axis of the reservoir cavity, and the reserved production wellbore is located on one side of the integrated injection-production wellbore.

[0011] Preferably, a drive chamber is fixedly connected to the outer side of the end cap of the integrated injection and production wellbore. The drive mechanism includes a worm gear, a worm, and a drive motor connected to one end of the worm, all disposed in the drive chamber. The drive motor is driven to rotate the worm, and the worm meshes with the worm gear to rotate the worm gear. The worm gear is fixedly connected to the end of the screw.

[0012] The multi-stage visualized gas injection-driven oil displacement experimental method for simulating green electricity fluctuations as described in this invention includes: Step S1: Inject steam or multi-component gas into the two-stage injection-production integrated wellbore connected in series; Step S2: Real-time acquisition of wellbore operating parameters using temperature and pressure detection devices; Step S3: The automatic control system calculates the change in steam dryness in the wellbore; Step S4: Adjust the electric heating power of each section according to the steam dryness and temperature distribution; when adjusting the electric heating power, automatically switch between intermittent heating mode, time-sharing heating mode or continuous heating mode according to the fluctuation of green electricity supply power, so as to achieve energy consumption optimization and stable control of steam quality. Step S5: Collect the produced fluid and perform recovery analysis.

[0013] The advantages of this invention compared to existing technologies are as follows: This invention achieves green and low-carbon operation by introducing green electricity into the thermal recovery experimental system, enabling renewable energy-driven experiments. Multi-stage wellbore electric heating can dynamically compensate for heat loss, improving steam dryness and displacement efficiency. The same device can complete huff-and-puff, steam drive, and SAGD experiments, significantly reducing experimental costs. Two-phase flow and condensation behavior can be directly observed, breaking through the traditional limitation of "invisible wellbore." The multi-stage horizontal well structure more closely resembles real oil reservoir development conditions. Attached Figure Description

[0014] Figure 1 This is a schematic diagram of one embodiment of the present invention.

[0015] Figure 2This is a cross-sectional structural diagram of an integrated injection and production wellbore.

[0016] Figure 3 yes Figure 2 A schematic diagram of the AA cross-sectional structure. Detailed Implementation

[0017] The present invention will now be described in detail with reference to the accompanying drawings and specific embodiments.

[0018] like Figure 1 As shown, the multi-stage visualized gas injection-driven oil recovery experimental device for simulating green electricity fluctuations according to the present invention includes an oil reservoir cavity 5, an integrated injection-production wellbore 10 disposed within the cavity of the oil reservoir cavity 5, a reserved production wellbore 25, a steam generator 21 disposed at the gas injection end of the integrated injection-production wellbore 10, and a condensate recovery tank 13 disposed at the exhaust end of the integrated injection-production wellbore 10. The oil reservoir cavity 5 includes a front cavity and a rear cavity arranged in series, and a connecting well section disposed between the front cavity and the rear cavity. The two ends of the connecting well section are respectively connected to the integrated injection-production wellbore 10 in the front cavity and the rear cavity through metal flanges. A visualization window 6 is provided on the sidewall of the connecting well section. This window 6 is made of high-pressure resistant, high-transmittance quartz glass, designed to withstand pressures of 0-5 MPa and temperatures exceeding 300℃. It is used to observe the fluid flow within the integrated injection-production wellbore 10, including the condensation front of steam, the migration of oil-water emulsions, and the evolution of the gas-liquid two-phase flow. In this embodiment, each reservoir cavity 5 is designed as a cylinder with an inner diameter of 300 mm and a length of 500 mm; the integrated injection-production wellbore 10 is designed as a cylinder with an inner diameter of 10 mm, and multiple gas injection perforations 4 are provided on the cylinder wall to simulate steam injection under perforated completion conditions. The reservoir cavity 5 is filled with quartz sand or actual oil sand to simulate a porous medium with specific porosity and permeability. The outer wall of the reservoir cavity 5 is covered with insulation material, and the visualization window 6 is also filled with insulation material to reduce heat loss and ensure thermal insulation during the experiment.

[0019] The front and rear sections of the reservoir cavity 5 are both cylindrical tanks with end caps at both ends. The integrated injection-production wellbore 10 is located on the central axis of the reservoir cavity 5, and the side wall of the integrated injection-production wellbore 10 is provided with gas injection perforations 4 that connect to the inner cavity of the reservoir cavity 5, so that the fluid in the inner cavity of the integrated injection-production wellbore 10 can diffuse into the inner cavity of the reservoir cavity 5 through the gas injection perforations 4. The reserved production wellbore 25 is located below the integrated injection-production wellbore 10, and the two are arranged parallel to each other. In addition, the inner cavity of the reservoir cavity 5 is also provided with a reservoir heater for heating the fluid in the reservoir, which is controlled by the reservoir heating control system 15.

[0020] In addition, the inner wall of the reservoir cavity 5 is equipped with thermocouples 1 for temperature detection. Multiple thermocouples 1 are distributed along the axial direction of the reservoir cavity 5 to monitor temperature field changes at different locations within the reservoir. The outer wall of the reservoir cavity 5 is equipped with a reservoir cavity pressure gauge 17 and a wellbore pressure gauge 171. The reservoir cavity pressure gauge 17 is used to detect the pressure inside the reservoir cavity 5, and the wellbore pressure gauge 171 is used to detect the pressure inside the integrated injection-production wellbore 10. An axially movable electric heating rod 9 is installed inside the cavity of the integrated injection-production wellbore 10. The electric heating rod 9 is used to heat the fluid inside the integrated production wellbore 10, and its power supply end is connected to the output end of the control unit 3. The electric heating rod 9 has an outer diameter of 6.1 mm, a length of 200 mm, a maximum power of 150 W, and its surface is covered with an insulating high-temperature resistant layer.

[0021] The signal acquisition terminal of the control unit 3 is connected to thermocouple 1, reservoir cavity pressure gauge 17, and wellbore pressure gauge 171. The power input terminal of the control unit 3 is connected to the green electricity simulation unit 2. The input terminal of the green electricity simulation unit 2 is connected to the fluctuating power supply simulating wind or photovoltaic power, and the output terminal is connected to the control unit 3. The control unit 3 adjusts the power and axial movement position of the electric heating rod 9 according to the data collected by thermocouple 1 and pressure gauge. The control unit 3 adjusts the on / off state and power of the electric heating rod 9 in real time according to the preset green electricity fluctuation curve, such as intermittent power supply or segmented power supply. At the same time, thermocouple 1 and pressure sensor are arranged inside the injection-production integrated wellbore 10 to monitor the steam dryness, temperature, and pressure in the wellbore in real time. The control unit 3 receives these signals and automatically adjusts the power of the electric heating rod 9 to perform secondary heating or supplemental heating of the steam, compensate for heat loss during transportation, and ensure that the steam dryness injected into the reservoir reaches the experimental set value.

[0022] like Figure 2 , Figure 3 As shown, the electric heating rod 9 is fixedly mounted on the slider 91, the slider 91 is slidably mounted on the slide rod 92, the slide rod 92 is parallel to the axis of the integrated injection-production wellbore 10, and both ends of the slide rod 92 are fixedly connected to the integrated injection-production wellbore 10. Figure 3As shown, there are at least two slide rods 92, which are inserted through the lower end of the slider 91, and the slider 91 can slide on the slide rods 92. A rotatable screw 93 is provided in the inner cavity of the integrated injection-production wellbore 10. The screw 93 is arranged parallel to the slide rods 92 and passes through the slider 91. The slider 91 and the screw 93 are connected by a threaded connection. When the screw 93 rotates, it pushes the slider 91 axially through the thread. The ends of the slide rods 92 and the screw 93 can be directly supported and connected to the end cover of the integrated injection-production wellbore 10, or connected to the end cover of the integrated injection-production wellbore 10 through bearings or bushings; alternatively, the ends of the slide rods 92 and the screw 93 can be connected to the inner wall of the integrated injection-production wellbore 10 through a bearing installed in the inner cavity of the integrated injection-production wellbore 10. One end of the screw 93 passes through the end cover of the integrated injection-production wellbore 10 and is connected to the drive mechanism for transmission.

[0023] As a specific embodiment of the drive mechanism that drives the screw 93 to rotate, such as Figure 2 As shown, a drive chamber 94 is fixedly connected to the outer side of the end cap of the injection-production integrated wellbore 10 away from the connecting section. The drive mechanism includes a worm gear 95, a worm 96, and a drive motor 97 connected to one end of the worm 96, all housed within the drive chamber 94. The drive motor 97 is driven by the worm 96 to rotate it, and the worm 96 meshes with the worm gear 95 to rotate it. The worm gear 95 is fixedly connected to the end of the screw 93. The ends of both the screw 93 and the worm gear 95 are connected to a partition 98 within the drive chamber 94 via bearings. The drive motor 97 is controlled by the control unit 3. When the drive motor 97 operates, the screw 93 rotates, and this rotation, in turn, drives the screw 93 to rotate via the worm gear 95. As the screw 93 rotates, it pushes the slider 91 to slide on the slide bar 92 via a thread. The electric heating rod 9 mounted on the slider 91 then moves axially, changing its position. A cable chain 901 is installed on the inner wall of the integrated injection-production wellbore 10. The power cord 902 of the electric heating rod 9 is installed on the cable chain 901. The cable chain 901 can restrain the power cord 902 so that it can move with the electric heating rod 9 without rubbing against the inner wall of the integrated injection-production wellbore 10. The structure and installation method of the cable chain are existing known technologies and will not be described in detail here. The end of the power cord 902 passes through the end cap of the integrated injection-production wellbore 10 and connects to the external control unit 3.

[0024] When the control unit 3 detects that the steam dryness of the injected reservoir is less than the experimental set value, it can increase the steam dryness of the injected reservoir by increasing the power of the electric heating rod 9 or moving the electric heating rod 9 toward the steam inlet position, so as to reach the experimental set value. Conversely, when the control unit 3 detects that the steam dryness of the injected reservoir is greater than the experimental set value, it can increase the steam dryness of the injected reservoir by decreasing the power of the electric heating rod 9 or moving the electric heating rod 9 away from the steam inlet position, so as to reach the experimental set value.

[0025] The gas injection sealing end cap 24 at the front end of the integrated injection-production wellbore 10 is connected to the steam generator 21 via a front-end shut-off valve 19 and a dryness regulator 20. This allows the steam generator 21 to be regulated by the dryness regulator 20 and then introduced into the integrated injection-production wellbore 10 via the front-end shut-off valve 19. Additionally, a high-pressure metering pump 23 is connected to the steam generator 21 via a check valve 22. The high-pressure metering pump 23 has an injection rate adjustment range of 5-200 ml / min and an operating pressure range of 0-5 MPa. The experimental water is pressurized by the high-pressure metering pump 23 and then enters the steam generator 21 through the check valve 22. The steam generator 21 heats the water to a maximum of 300°C, generating wet saturated steam. The steam dryness is then initially regulated by the dryness regulator 20 before being injected into the integrated injection-production wellbore 10 via the front-end shut-off valve 19 and the gas injection sealing end cap 24. A flow meter and pressure gauge can also be installed at the outlet of the steam generator 21 on the pipeline for real-time monitoring of the injected fluid parameters.

[0026] The injection-production wellbore 10 is equipped with a back pressure valve 11 at its rear end, and the rear end sealing cap of the injection-production wellbore 10 is connected to the condensate recovery tank 13 through the rear end shut-off valve 12, so as to recover the condensate discharged from the injection-production wellbore 10.

[0027] The condensate recovery tank 13 is a pressurized vessel capable of operating under pressure for recovering and metering produced fluid. During steam injection experiments, the integrated injection-production wellbore 10 is used for simultaneous injection and production. After the gas injection phase, the front-end shut-off valve 19 is closed, and the back pressure valve 11 and the rear-end shut-off valve 12 are opened to guide the produced fluid into the condensate recovery tank 13. During steam drive or SAGD experiments, the integrated injection-production wellbore 10 serves as the injection well for continuous gas injection, while the reserved production wellbore 25 serves as the production well. The produced fluid is collected via the rear-end shut-off valve 12 and the condensate recovery tank 13.

[0028] The multi-stage visualized gas injection-driven oil displacement experimental method for simulating green electricity fluctuations as described in this invention includes the following steps: Step S1: Inject steam or multi-component gas into the two-section injection-production integrated wellbore 10 connected in series; Step S2: Real-time acquisition of wellbore operating parameters using temperature and pressure detection devices; Step S3: The automatic control system calculates the change in steam dryness in the wellbore; Step S4: Adjust the electric heating power of each section according to the steam dryness and temperature distribution; when adjusting the electric heating power, automatically switch between intermittent heating mode, time-sharing heating mode or continuous heating mode according to the fluctuation of green electricity supply power, so as to achieve energy consumption optimization and stable control of steam quality. Step S5: Collect the produced fluid and perform recovery analysis.

[0029] The operation method of the device of the present invention will be described in detail below with reference to specific embodiments.

[0030] Experiment 1: Simulation Experiment of Steam Intake and Output Coupled with Green Electricity Waves Preparation phase: According to the experimental design, the reservoir cavity 5 is filled with sorted quartz sand and saturated with simulated oil to establish the initial oil saturation. The front-end shut-off valve 19 is closed, the rear-end shut-off valve 12 is opened, and the back pressure valve 11 is set to the simulated formation pressure, for example, 3 MPa.

[0031] Green electricity mode setting: In control unit 3, select "intermittent heating mode" and set the green electricity fluctuation curve to simulate photovoltaic power supply: full power heating for 8 hours during the day and no heating at night, or set other fluctuation parameters according to research needs.

[0032] Gas Injection Stage (Intake): Start the high-pressure metering pump 23 and set the injection rate to 50 ml / min. Open the front-end shut-off valve 22, start the steam generator 21, open the front-end shut-off valve 19, close the rear-end shut-off valve 12, and set the outlet steam temperature to 280℃. Simultaneously, control the electric heating rod 9 to move to its initial position. The control unit 3 controls the electric heating rod 9 to heat according to the green electricity fluctuation curve. When the photovoltaic analog signal is high, the electric heating rod operates at full power, increasing the steam dryness in the wellbore to over 85%; when the signal is low, heating is paused. Observe the changes in steam flow patterns at different heating stages through the visualization window 6.

[0033] Well-closing stage: After reaching the preset steam injection volume, shut down the high-pressure metering pump 23 and steam generator 21, stop heating, and close all valves. Use the insulation material 18 outside the reservoir cavity to maintain the temperature and simulate the heat diffusion process. The well-closing time is set according to the experimental plan, for example, 2 hours.

[0034] Production stage (outflow): Open the back pressure valve 11 and the rear shut-off valve 12. The pressure inside the reservoir decreases, and the oil, gas, and water mixture is produced from the rear end of the injection-production wellbore 10 under the action of pressure differential, entering the condensate recovery tank 13. Record the production volume and analyze the oil-water ratio.

[0035] Data Analysis: The computer records temperature field changes, pressure fluctuations, and output data in real time throughout the process. The cumulative oil production and oil-to-gas ratio are compared under different green electricity fluctuation modes to evaluate the impact of green electricity fluctuations on throughput.

[0036] Table 1. Results of steam injection experiments under different green electricity fluctuation conditions Table 1 shows that, under the same steam injection temperature, water injection volume, and wellbore shut-in time, wellbore supplementation significantly improved the steam huff and puff effect. In the no-steam-supplementation condition T1, the average steam dryness was only 68.4%, the highest reservoir temperature was low, and both oil production and recovery rate were the lowest, indicating significant heat loss during steam transport and entry into the reservoir. In the continuous and stable power supply condition T2, the average steam dryness reached 88.7%, the recovery rate increased to 31.2%, and the oil-steam ratio reached 0.137, demonstrating the optimal thermal recovery effect. This indicates that continuous supplementation can effectively maintain steam quality, improve the viscosity reduction of heavy oil, and enhance heat transfer to deeper reservoirs. The recovery rate of the simulated photovoltaic fluctuation condition T3 was 27.5%, lower than the continuous power supply condition but significantly higher than the no-steam-supplementation condition. This shows that although intermittent green power supply causes fluctuations in steam dryness and reservoir temperature, it can still effectively improve steam dryness and enhance huff and puff development during the high-power daytime supplementation phase.

[0037] The recovery rate under the time-of-use power supply condition T4 was 29.6%, close to that under continuous power supply, and superior to that under the simple day-night intermittent power supply condition T3. This result indicates that a well-designed heating-shutdown cycle can maintain high steam dryness and a relatively stable reservoir temperature field while reducing energy consumption. The recovery rate under the highly fluctuating power supply condition T5 was 23.0%, indicating that when the fluctuation amplitude of green power is too large and the duration of low power is long, steam dryness decreases significantly, the thermal front advance speed slows down, and the degree of crude oil mobilization decreases. Therefore, prolonged operation without supplemental heating should be avoided during green power coupled with steam huff and puff; time-of-use heating or energy storage smoothing control methods are preferable.

[0038] For steam injection experiments, green electricity fluctuations affect steam dryness, reservoir temperature field, and final recovery rate. Continuous reheating has the best effect, but consumes more energy; time-sharing heating mode shows a better balance between recovery rate and energy consumption, and is more suitable as an optimized operation mode under green electricity fluctuation conditions.

[0039] Experiment 2: SAGD Process Simulation Experiment Preparation phase: Confirm that the integrated injection-production wellbore 10 and the reserved production wellbore 25 are both intact. Establish a saturated oil model in the reservoir cavity 5.

[0040] Wellbore positioning: Start the control unit 3 to make the drive motor 97 work, and move the electric heating rod 9 to a position away from the steam inlet of the injection and production wellbore 10 through the screw 93, simulating the full thermal compensation from the heel to the toe of the horizontal well.

[0041] Injection and Production Operation: Open the front-end shut-off valves 19 and 22 and the rear-end shut-off valve 12, and start the high-pressure metering pump 23 and steam generator 21. The control unit 3 automatically starts the electric heating rod 9 for supplemental heating based on the steam dryness signal monitored in the wellbore (e.g., below 70%), ensuring the steam dryness of the injected reservoir remains stable at around 90%. The production wellbore 25 is reserved for continuous production, and the fluid enters the condensate recovery tank 13 through the rear-end shut-off valve 12. Adjust the back pressure valve 11 to control the production pressure differential.

[0042] Visual observation: During the experiment, the expansion morphology of the steam chamber, the steam breakthrough time, and the flow state of oil-water emulsion were observed and recorded through visualization window 6.

[0043] Data Acquisition: The computer collects real-time temperature and pressure data, as well as cumulative oil and water production, from both injection and production wells. After the experiment, displacement characteristic curves are plotted based on the collected data to analyze the impact of steam dryness and injection rate on the SAGD development effect.

[0044] Table 2. Experimental results of SAGD under different steam dryness conditions. Table 2 shows that steam dryness has a significant impact on the development effect of SAGD. When the target steam dryness increases from 70% to 90%, the steam breakthrough time decreases from 92 min to 61 min, and the recovery rate increases from 26.4% to 39.5%. This indicates that high-dryness steam has a stronger heat-carrying capacity, which is conducive to the rapid formation and expansion of the steam chamber, thereby improving crude oil viscosity reduction and displacement efficiency. Under the same injection rate of 50 mL / min, SA3 condition, using a movable electric heating rod for dynamic supplementary heating, achieved the highest recovery rate of 39.5%. Compared with SA1 and SA2, which use fixed inlet heating, movable supplementary heating can reduce heat loss along the wellbore, maintain a high level of steam quality at the far end, promote the expansion of the steam chamber towards the horizontal well toe, and improve the uniformity of reservoir utilization. Comparing SA3, SA4, and SA5, it can be seen that the injection rate also affects the development effect. The low injection rate condition SA4 has a longer steam breakthrough time, lower water production, and the highest oil-steam ratio, indicating that a lower injection rate is beneficial for sufficient heat transfer and stable crude oil flow, but the development speed is slower. The high injection rate condition SA5, although having the shortest steam breakthrough time, shows a significant increase in cumulative water production and a decrease in the oil-steam ratio, indicating that excessively high injection rates can easily cause premature steam breakthrough, reducing thermal efficiency.

[0045] For SAGD experiments, higher steam dryness and mobile reheating methods are beneficial for improving steam chamber expansion efficiency and recovery; however, higher injection rates are not always better. Considering recovery, oil-to-steam ratio, and steam breakthrough time, the optimal performance is achieved with a target steam dryness of approximately 90%, a moderate injection rate of 50 mL / min, and mobile reheating.

[0046] The device of this invention is equipped with a green electricity supply module. The control unit can simulate the fluctuation characteristics of green electricity such as wind power and photovoltaic power, and realize multiple modes such as intermittent heating, long-cycle heating, and time-segmented heating. This can not only evaluate the impact of energy fluctuations on oil extraction, but also improve the system's energy efficiency through thermal storage simulation.

[0047] The system is equipped with adjustable electric heating moving devices and electric heating rods within the multi-section horizontal gas injection wellbore. Based on real-time monitoring of wellbore temperature, pressure, and dryness data, the system dynamically adjusts the heating intensity, improves steam dryness quality online, effectively solves the problem of heat loss during steam transportation, and thus accurately evaluates the limits of enhanced oil recovery.

[0048] The device employs a modular design, enabling steam injection and production: It utilizes injection wells for simultaneous injection and production within the same well. Steam Drive / SAGD: It simulates displacement experiments under different well network configurations using a combination of injection wells and reserved production wells.

[0049] A visualization window is embedded between the two gas injection well sections, breaking the obstruction of traditional metal pipelines. Researchers can directly observe the flow phase, emulsification state, and flow channel evolution of steam and multi-component fluids (such as gas, water, and oil) under high temperature and high pressure.

[0050] In summary, this invention, by coupling a green electricity supply module, a multi-segment movable electrically heated wellbore, and a visualization window, solves the problems of existing technologies that cannot simulate green electricity fluctuations, cannot finely control steam dryness, cannot intuitively observe flow patterns, and cannot achieve multi-process switching. It provides an effective experimental platform for the low-carbon and refined research of heavy oil thermal recovery.

Claims

1. A multi-stage visual gas injection-driven oil recovery experimental device for simulating green electricity fluctuations, comprising an oil reservoir cavity (5), an integrated injection-production wellbore (10) and a reserved production wellbore (25) disposed within the inner cavity of the oil reservoir cavity (5), a steam generator (21) disposed at the gas injection end of the integrated injection-production wellbore (10), and a condensate recovery tank (13) disposed at the exhaust end of the integrated injection-production wellbore (10). The inner wall of the oil reservoir cavity (5) is provided with a thermocouple (1) for temperature detection, and the outer wall of the oil reservoir cavity (5) is provided with a reservoir cavity pressure gauge (17) and a wellbore pressure gauge (171) for detecting the pressure within the oil reservoir cavity (5). The reservoir cavity pressure gauge (17) is used to detect the pressure within the oil reservoir cavity (5), and the wellbore pressure gauge (171) is used to detect the pressure within the integrated injection-production wellbore (10). The device is characterized in that... An axially movable electric heating rod (9) is installed in the inner cavity of the injection-production integrated wellbore (10). The electric heating rod (9) is used to heat the fluid in the injection-production integrated wellbore (10). The power supply end of the electric heating rod (9) is connected to the output end of the control unit (3). The signal acquisition end of the control unit (3) is connected to the thermocouple (1), the reservoir cavity pressure gauge (17), and the wellbore pressure gauge (171). The power input end of the control unit (3) is connected to the green electricity simulation unit (2). The control unit (3) adjusts the power and axial movement position of the electric heating rod (9) according to the data collected by the thermocouple (1) and the pressure gauge.

2. The multi-stage visualized gas injection-driven oil displacement experimental device for simulating green electricity fluctuations according to claim 1, characterized in that: The reservoir cavity (5) includes a front cavity and a rear cavity arranged in series, and a connecting well section arranged between the front cavity and the rear cavity. The two ends of the connecting well section are respectively connected to the injection-production wellbore (10) in the front cavity and the rear cavity. A visualization window (6) is provided on the side wall of the connecting well section. The visualization window (6) is used to observe the fluid flow state in the injection-production wellbore (10).

3. The multi-stage visualized gas injection-driven oil displacement experimental device for simulating green electricity fluctuations according to claim 1 or 2, characterized in that: The electric heating rod (9) is fixedly installed on the slider (91), the slider (91) is slidably installed on the slide rod (92), the slide rod (92) is parallel to the axis of the injection-production wellbore (10) and both ends of the slide rod (92) are fixedly connected to the injection-production wellbore (10), a rotatable screw (93) is provided in the inner cavity of the injection-production wellbore (10), the screw (93) is parallel to the slide rod (92), the slider (91) is threadedly connected to the screw (93), and one end of the screw (93) passes through the end cap of the injection-production wellbore (10) and is connected to the drive mechanism.

4. The multi-stage visualized gas injection-driven oil displacement experimental device for simulating green electricity fluctuations according to claim 2, characterized in that: The front and rear sections of the reservoir cavity (5) are both cylindrical tanks with end caps at both ends. The injection-production integrated wellbore (10) is located on the central axis of the reservoir cavity (5), and the reserved production wellbore (25) is located on one side of the injection-production integrated wellbore (10).

5. The multi-stage visualized gas injection-driven oil displacement experimental device for simulating green electricity fluctuations according to claim 3, characterized in that: The injection-production wellbore (10) has a drive chamber (94) fixedly connected to the outside of the end cap. The drive mechanism includes a worm gear (95), a worm (96) and a drive motor (97) connected to one end of the worm (96) in the drive chamber (94). The drive motor (97) is connected to the worm (96) for driving the worm (96) to rotate. The worm (96) meshes with the worm gear (95) for driving the worm gear (95) to rotate. The worm gear (95) is fixedly connected to the end of the screw (93).

6. A multi-stage visualized gas injection-driven oil displacement experimental method for simulating green electricity fluctuations, characterized in that, include: Step S1: Inject steam or multi-element gas into the two-section injection-production integrated wellbore (10) connected in series; Step S2: Real-time acquisition of wellbore operating parameters using temperature and pressure detection devices; Step S3: The automatic control system calculates the change in steam dryness in the wellbore; Step S4: Adjust the electric heating power of each section according to the steam dryness and temperature distribution; when adjusting the electric heating power, automatically switch between intermittent heating mode, time-sharing heating mode or continuous heating mode according to the fluctuation of green electricity supply power, so as to achieve energy consumption optimization and stable control of steam quality. Step S5: Collect the produced fluid and perform recovery analysis.

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