A method and experimental device for judging gas channeling in gas injection development of an oil reservoir

Abstract

A kind of oil reservoir gas injection development gas channeling discrimination method and experimental device, discrimination method includes the following steps: well stream sampling is carried out to production well in field;Long core displacement experiment is carried out to production well's well stream sampling;The injection pore volume multiple, pressure difference, flow rate, production and oil-gas component constitution of long core displacement injection end and production end in long core displacement experiment process are analyzed, when oil displacement efficiency drops sharply and gas-oil ratio rises sharply, it is marked that gas channeling occurs;Synthesize injection well monitoring result, production well monitoring result and long core displacement experiment result, form chart to carry out gas channeling discrimination.Experimental device includes long core clamping main body, high pressure displacement system, back pressure control and metering system, long core clamping main body includes long core holder and control panel, control panel can control long core holder to adjust the direction of internal long core displacement model according to formation dip angle.The present application can realize early warning and has higher accuracy under the condition of simple operation.

Description

Technical Field

[0001] This invention belongs to the field of oilfield development technology, specifically relating to a method and experimental apparatus for identifying gas channeling during reservoir gas injection development. Background Technology

[0002] Gas injection development technology is a commonly used technique in oilfield development. As early as the 1950s, the United States began implementing gas injection development technology to improve reservoir recovery. Currently, gas injection development technology accounts for one-third of all enhanced oil recovery technologies worldwide, playing a crucial role, especially in reservoirs with low permeability and difficult water injection. During gas injection development, the key to its success lies in maximizing the contact between the injected gas medium and the underground crude oil, enhancing the interaction between them, and delaying the gas medium's breakthrough to the production well. This necessitates the analysis and identification of gas medium breakthrough and gas channeling.

[0003] Currently, there are two main standards for identifying gas channeling in China (Zhang Juan, 2018): empirical discrimination and dynamic monitoring (Peng Haiyang et al., 2016). The empirical discrimination method identifies gas channeling based on dynamic production parameters during gas injection and development, such as changes in the gas-oil ratio, gas production (Zhao Lun et al., 2010), recovery rate, gas chromatography, and differential pressure (Zheng Jilong et al., 2014). The dynamic monitoring method, on the other hand, relies on in-situ microseismic technology and tracer technology to monitor the migration patterns at the gas drive front in real time. The following fundamental problems still need to be addressed in current gas channeling identification methods:

[0004] (1) Advancement of gas channeling detection (whether it can provide early warning, rather than detecting gas channeling when it occurs); (2) Accuracy of the gas channeling detection process (whether it can establish a comprehensive and systematic analysis method for injection and production parameters that can be obtained on-site, such as seepage resistance, content of components at the production end, gas-oil ratio, and degree of recovery, rather than using a single parameter for judgment); (3) Real-time and ease of gas channeling detection (whether it can quickly detect gas channeling by obtaining simple on-site and laboratory parameters, and provide the change law of the production end output throughout the entire life cycle of gas injection development, reducing operation and costs). Summary of the Invention

[0005] The purpose of this invention is to address the problems in the prior art by providing a method and experimental apparatus for identifying gas channeling during gas injection development in oil reservoirs. Through indoor experiments and field studies, the invention investigates the displacement characteristics and compositional variations of the produced fluid during gas injection development. It systematically analyzes the variations in seepage resistance, produced-end component content, gas-oil ratio, and recovery rate, generating discrimination charts for each stage of gas channeling. This chart supports the judgment of gas channeling and the timing of control measures during oilfield gas injection production, enabling advanced early warning with higher accuracy.

[0006] To achieve the above objectives, the present invention provides the following technical solution:

[0007] A method for identifying gas channeling during reservoir gas injection development includes the following steps:

[0008] On-site sampling of well fluid from the production well;

[0009] Long core displacement experiments were conducted by sampling well fluid from production wells.

[0010] The volume ratio of gas injection pores, pressure difference, flow rate, production rate and oil and gas composition at the injection and production ends of long core displacement experiments were analyzed. When the oil displacement efficiency drops sharply and the gas-oil ratio rises sharply, it indicates that gas channeling has occurred.

[0011] By combining the monitoring results of injection wells, production wells, and long core displacement experiments, a chart is generated to identify gas channeling.

[0012] As a preferred embodiment of the gas channeling identification method for reservoir gas injection development of the present invention, before sampling the well fluids of the production well, the composition of the injection medium and the injection pressure of the injection well are monitored, as well as the production output, gas-oil ratio and production pressure of the production well are monitored; the sampling frequency of the well fluids is 1 to 3 times / month.

[0013] As a preferred embodiment of the gas channeling discrimination method for reservoir gas injection development of the present invention, in the step of sampling well fluids from production wells to conduct long core displacement experiments, horizontal or vertical gas injection displacement experiments are directly performed after saturating the long core model with formation water and formation oil under the target reservoir formation temperature and formation pressure.

[0014] As a preferred embodiment of the gas channeling identification method for reservoir gas injection development of the present invention, in the step of taking samples of well fluid from production wells to carry out long core displacement experiments, the gas propulsion speed during the experiment is controlled to be consistent with the gas propulsion speed during the actual gas injection development process in the field; the injected gas medium is configured according to the actual gas source components of the oilfield.

[0015] As a preferred embodiment of the gas channeling identification method for reservoir gas injection development of the present invention, in the step of sampling the well fluid of the production well to carry out long core displacement experiment, the produced oil and gas volume is collected and measured for every 0.1HCPV injected, and the changes in gas injection equipment reading, injection pressure, confining pressure and back pressure are recorded, and the experiment ends when no more oil is produced.

[0016] Several samples of produced oil and gas were collected before and after the gas injection breakthrough.

[0017] As a preferred embodiment of the gas channeling identification method for reservoir gas injection development of the present invention, in the step of conducting long core displacement experiments by sampling well fluids from production wells, the long core displacement experiment materials include:

[0018] Cores: The actual cores taken from the target layer of the oil well in the reservoir are numbered, trimmed, and arranged in a mixed and average manner to form a long core group. The cores are connected with filter paper, sealed with Teflon heat shrink tubing, and then put into fluororubber tubes.

[0019] Formation oil and injected hydrocarbon gas: The combined injection station uses reservoir-mixed formation oil and standard reservoir gas;

[0020] Simulated formation water: The mineralization of formation water is used based on the data recorded.

[0021] As a preferred embodiment of the gas channeling identification method for reservoir gas injection development of the present invention, in the step of sampling well fluids from the production well to conduct long core displacement experiments, the preparation for the long core displacement experiments is first carried out according to the following steps:

[0022] 1) When assembling the cores in sequence, add multiple layers of filter paper between the cores;

[0023] 2) After the core is assembled, temperature and pressure tests are conducted according to the maximum pressure and temperature designed in the experiment to confirm that the model has no leakage.

[0024] As a preferred embodiment of the gas channeling identification method for reservoir gas injection development of the present invention, the specific steps of conducting long core displacement experiments by sampling well fluid from the production well include:

[0025] 1) Use methanol to clean the water in the core and petroleum ether to clean the oil in the core until the produced fluid is clear and transparent again. Finally, blow it dry with nitrogen and vacuum it.

[0026] 2) Under formation temperature and pressure, the core is first saturated with water and then with oil, and after saturation, it is left to age statically.

[0027] 3) Adjust the model orientation according to the dip angle of the strata;

[0028] 4) Maintain outlet pressure and implement gas injection for displacement until the gas content reaches 100% and then stop the displacement.

[0029] 5) Collect several samples of produced oil and gas before and after the breakthrough of the injected gas medium, and perform component composition analysis on each.

[0030] An experimental apparatus for implementing the gas channeling detection method in reservoir gas injection development includes a long core holder, a high-pressure displacement system, and a back pressure control and metering system. The long core holder includes a long core holder and a control panel. The high-pressure displacement system includes two parallel high-pressure displacement pumps. One high-pressure displacement pump is connected to the first inlet of the long core holder via a pipeline equipped with a pressure gauge and a valve. The other high-pressure displacement pump is connected to one end of a composite injection device via a pipeline equipped with a pressure gauge and a valve. The other end of the composite injection device is connected to the long core holder. The second inlet of the device is connected; the composite injection equipment includes an oil storage tank, a water storage tank, and a natural gas storage tank arranged in parallel, with valves installed at both ends of the oil storage tank, water storage tank, and natural gas storage tank; the back pressure control and metering system includes a back pressure valve connected to the outlet of the long core holder via a pipeline equipped with a valve, and test tubes, conical flasks, and a gas meter connected in sequence to the back pressure valve via pipelines; the tilt angle of the long core holder is adjustable, and the control panel can control the long core holder to adjust the direction of the internal long core displacement model according to the formation dip angle.

[0031] Compared with the prior art, the present invention has at least the following beneficial effects:

[0032] This invention analyzes the gas injection pore volume ratio, pressure difference, flow rate, production rate, and hydrocarbon composition at the injection and production ends of long core displacement experiments. A novel, comprehensive, and systematic method for identifying gas channeling is established, encompassing in-situ injection and production parameters, fluid composition at different production stages, and laboratory long core displacement results. Finally, the results from injection well monitoring, production well monitoring, and long core displacement experiments are integrated to create charts for gas channeling identification. Compared to existing empirical and dynamic monitoring methods, the proposed method is simple to operate, has higher accuracy, and most importantly, provides early warning, supporting in-situ control. Attached Figure Description

[0033] Figure 1 This is a schematic diagram of the experimental apparatus according to an embodiment of the present invention;

[0034] Figure 2 This is a graph showing the changes in key parameters during the hydrocarbon injection development process according to an embodiment of the present invention.

[0035] Figure 3 This is a diagram illustrating the gas channeling identification method for hydrocarbon injection in an embodiment of the present invention.

[0036] In the attached diagram: 1-long core holder; 2-control panel; 3-high pressure displacement pump; 4-pressure gauge; 5-compound injection device; 6-back pressure valve; 7-test tube; 8-conical flask; 9-gas meter. Detailed Implementation

[0037] To further illustrate and explain the technical process, technical details, and technical advantages of this invention, the following detailed explanation of the gas channeling identification method for reservoir gas injection development is provided in conjunction with embodiments and accompanying drawings. The illustrative and exemplary embodiments and their schematic diagrams described below are for illustrative purposes only and are not intended to limit the scope of this invention.

[0038] Example 1

[0039] The present invention provides a method for identifying gas channeling during reservoir gas injection development, comprising the following steps:

[0040] S1. Real-time monitoring of the composition of the gas injection medium and the injection pressure of the injection well.

[0041] S2. Real-time production monitoring of on-site production wells, gas-oil ratio detection, and production pressure monitoring.

[0042] S3. On-site production well fluid sampling, at a frequency of 1 to 3 times per month.

[0043] S4. Conduct long core displacement experiments on the samples; the long core displacement experiment scheme includes: 1) After saturating the long core model with formation water and formation oil under the target reservoir formation temperature and formation pressure, conduct horizontal or vertical gas injection displacement experiments directly; 2) The injected gas medium is prepared according to the actual gas source composition of the oilfield; 3) Control the gas propulsion speed as much as possible to be consistent with the gas propulsion speed in the actual gas injection development process in the field; 4) During the experiment, collect and measure the produced oil and gas volume every 0.1HCPV injected, and record the changes in pump reading, injection pressure, confining pressure and back pressure, and end the experiment when oil production ceases; 5) Collect several produced oil and gas samples before and after the gas injection breakthrough, and perform composition analysis respectively. The materials for the long core displacement experiment include: 1) Cores: All cores used in the experiment are real cores taken from the target formation of oil wells in the reservoir. Cores with relatively little damage are selected, numbered, trimmed, and arranged in a harmonized and averaged manner to form long core groups. The cores are connected with filter paper, sealed with Teflon heat shrink tubing, and then placed in fluororubber tubes. 2) Formation oil and injected hydrocarbon gas: Reservoir-mixed formation oil and gas injected from a joint station near the standard reservoir are used. 3) Simulated formation water: Formation water salinity shown in the original data is used. The preparation for the long core displacement experiment includes: 1) Assembling the cores in sequence, adding multiple layers of filter paper between them to reduce the impact of fluid accumulation or uneven distribution between the cores on the experiment; 2) After the cores are assembled, connecting the experimental flow, conducting temperature and pressure tests according to the maximum pressure and temperature designed in the experiment to confirm that the model has no leakage. The steps of the long core displacement experiment include: 1) Washing the water in the core with methanol and the oil in the core with petroleum ether until the produced fluid is clear and transparent again, and finally drying it with nitrogen and evacuating it; 2) Saturating the core with water and then oil under formation temperature and pressure, and letting it stand for aging for 1 month after saturation; 3) Closing the model inlet and adjusting the model direction according to the formation dip angle; 4) Maintaining the outlet pressure to carry out gas displacement until the gas content is 100% and then ending the displacement; 5) Collecting several produced oil and gas samples intensively before and after the breakthrough of the injected gas medium, and performing component composition analysis respectively.

[0044] S5. Analyze the HCPV, pressure difference, flow rate, production rate, and oil and gas composition at the injection and production ends of long core displacement to form a regular method.

[0045] S6, monitoring results of centralized injection wells, monitoring results of production wells, and displacement results of long core samples are used to form a gas channeling discrimination chart.

[0046] In one implementation, the following is adopted: Figure 1The experimental setup shown implements the long core displacement experiment in step S4 of the reservoir gas injection development gas channeling identification method of the present invention. The setup includes a long core clamping body, a high-pressure displacement system, and a back pressure control and metering system. The long core clamping body includes a long core clamp 1 and a control panel 2. The high-pressure displacement system includes two high-pressure displacement pumps 3 arranged in parallel. One high-pressure displacement pump 3 is connected to the first inlet of the long core clamp 1 via a pipeline equipped with a pressure gauge 4 and a valve. The other high-pressure displacement pump 3 is connected to one end of a composite injection device 5 via a pipeline equipped with a pressure gauge 4 and a valve. The other end of the composite injection device 5 is connected to the second inlet of the long core clamp 1. The composite injection device 5 includes an oil storage tank, a water storage tank, and a natural gas storage tank arranged in parallel. Valves are installed at both ends of the gas storage tank, oil storage tank, water storage tank, and natural gas storage tank. The back pressure control and metering system includes a back pressure valve 6 connected to the outlet of the long core holder 1 via a pipeline equipped with a valve, and test tubes 7, conical flasks 8, and gas meters 9 connected to the back pressure valve 6 via pipelines. The tilt angle of the long core holder 1 is adjustable, and the control panel 2 can control the long core holder 1 to adjust the direction of the internal long core displacement model according to the formation dip angle. The device can realize multiple working modes such as constant pressure, constant speed, and constant volume.

[0047] Example 2

[0048] This embodiment uses the top-injection hydrocarbon gas gravity drive development of reservoir D as an example to verify the gas channeling discrimination method for reservoir gas injection development proposed in this invention. After implementing gas injection development, the overall water cut decreased, the oil wells continued to increase oil production, and the development effect was significant.

[0049] Basic reservoir parameters: high burial depth (5000–6000 m), high pressure (>60 MPa), high temperature (100–150 °C), high salinity (>20 × 10⁴ mg / L), high oil-bearing height (>100 m), oil layer thickness (>40 m), average porosity 10–15%, average permeability 20–100 md. Detailed methods and steps in this embodiment include:

[0050] S1. Real-time monitoring of the composition of the gas injection medium and the injection pressure of the injection well.

[0051] S2. Real-time production monitoring of on-site production wells, gas-oil ratio detection, and production pressure monitoring.

[0052] S3. On-site production well fluid samples are taken once a month. The properties of the well fluid are shown in Table 1.

[0053] Table 1. Field sampling parameters for single-layer experiments

[0054]

[0055] S4. Conduct long core displacement experiments on the samples.

[0056] The experimental scheme for long core displacement in step S4 includes:

[0057] 1) Under the formation temperature of 140℃ and formation pressure of 45MPa in the target reservoir, a vertical gas injection displacement experiment was carried out directly after the formation water and formation oil in the long core model (simulating top hydrocarbon gas injection gravity drive).

[0058] 2) The injected gas medium is configured according to the actual gas source composition of the oilfield (Table 2);

[0059] Table 2. Hydrocarbon composition of actual gas source at the site.

[0060] gas components mole fraction / % gas components mole fraction / % carbon dioxide 2.28 Isobutane 0.25 methane 86.03 n-Butane 0.35 Ethane 8.60 isopentane 0.07 propane 2.35 n-Pentane 0.07

[0061] 3) Control the gas propulsion speed to be consistent with the actual gas propulsion speed during the gas injection development process on site as much as possible;

[0062] 4) During the experiment, the amount of oil and gas produced was collected and measured every time 0.1HCPV was injected, and the changes in pump reading, injection pressure, confining pressure and back pressure were recorded. The experiment ended when no more oil was produced.

[0063] 5) Collect several samples of produced oil and gas before and after the gas injection breakthrough, and perform component composition analysis on each.

[0064] The long core displacement test materials in step S4 include:

[0065] 1) Core samples: All core samples used in the experiment were genuine core samples taken from the target formation of the oil wells in the reservoir. Core samples with relatively little damage were selected, numbered, trimmed, and arranged in a harmonized average order to form long core groups. The core samples were connected with filter paper, sealed with Teflon heat shrink tubing, and then placed in fluororubber tubes. The total length of the assembled core samples was 62.04 cm. The gas permeability of the core group was 1.77 × 10⁻³ μm². The measured saturated formation water volume was 66.59 mL, the water produced during the saturation process was 43.5 mL, the hydrocarbon pore volume (HCPV) was 43.5 mL, and the initial oil saturation was 65.33%.

[0066] 2) Formation oil and injected hydrocarbon gas: Formation oil and injected gas from a joint station near the reservoir were used (Table 1, Table 2).

[0067] 3) Simulated formation water: The formation water salinity shown in the original data is 233,866.5 mg / L.

[0068] The preparation for the long core displacement experiment in step S4 includes:

[0069] 1) The cores are assembled in sequence, with multiple layers of filter paper added between them to reduce the impact of fluid accumulation or uneven distribution between the cores on the experiment;

[0070] 2) After the core is assembled, connect the experimental procedure and conduct temperature and pressure tests according to the maximum pressure and temperature designed in the experiment to confirm that the model has no leakage.

[0071] Step S4, the long core displacement experiment steps include:

[0072] 1) Use methanol to clean the water in the core and petroleum ether to clean the oil in the core until the produced fluid is clear and transparent again. Finally, blow it dry with nitrogen and vacuum it.

[0073] 2) Under formation temperature and pressure conditions, the core was first saturated with water and then with oil, and after saturation, it was left to stand and age for 1 month.

[0074] 3) Close the model inlet and adjust the model orientation according to the formation dip angle;

[0075] 4) Maintain outlet pressure and implement gas injection for displacement until the gas content reaches 100% and then stop the displacement.

[0076] 5) Collect oil and gas samples intensively several times before and after the breakthrough of the injected gas medium, and perform component composition analysis on each sample.

[0077] S5. Analyze the HCPV, pressure differential, flow rate, production rate, and hydrocarbon composition at the injection and production ends of long core displacement to establish a systematic approach. The analysis of long core displacement results includes:

[0078] As the injected HCPV increases, the recovery rate increases uniformly, the gas-oil ratio remains constant, and the seepage resistance rises rapidly. When the injected hydrocarbon gas reaches 0.56 HCPV, the seepage resistance drops to its lowest point, indicating gas breakthrough. When the injected hydrocarbon gas reaches 0.86 HCPV, the recovery rate drops sharply, and the gas-oil ratio rises linearly, indicating gas channeling. Figure 2 As shown.

[0079] S6, monitoring results of centralized injection wells, monitoring results of production wells, and displacement results of long core samples are used to form a gas channeling discrimination chart.

[0080] Analysis of displacement results from long core samples includes:

[0081] 1) Considering the different mass transfer capabilities of different components of crude oil and injected gas, the produced fluid is divided into several pseudo-components such as C1+N2, C2~C6, C7~C16, and C17+.

[0082] 2) During the stage of increasing and stabilizing seepage resistance (before injection of 0.27 HCPV), the content of each component segment at the producing end showed no significant change, closely resembling the component distribution of formation oil. When seepage resistance began to decrease (before 0.56 HCPV), the content of C17+ component at the producing end decreased, while other components increased slightly. After the injected gas breakthrough (0.56 HCPV to 0.86 HCPV), the contents of C1+N2 and C2-C6 components at the producing end increased rapidly, while the contents of C7+ component decreased rapidly. Figure 3 As shown.

[0083] This invention provides a method for identifying gas channeling during reservoir gas injection development. Through laboratory experiments and field studies, it investigates the displacement characteristics and compositional variations of the produced fluid during gas injection development. The method systematically analyzes the changes in seepage resistance, produced-end component content, gas-oil ratio, and recovery rate, generating discrimination charts for each stage of gas channeling. This chart supports the identification of gas channeling and the timing of interventions during oilfield gas injection production. This invention offers high accuracy while remaining easy to operate, providing early warning and support for on-site control measures.

[0084] The above description is merely a specific embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for identifying gas channeling during gas injection development in an oil reservoir, characterized in that, Includes the following steps: On-site sampling of well fluid from the production well; Long core displacement experiments were conducted by sampling well fluid from production wells. The volume ratio of gas injection pores, pressure difference, flow rate, production rate and oil and gas composition at the injection and production ends of long core displacement experiments were analyzed. When the oil displacement efficiency drops sharply and the gas-oil ratio rises sharply, it indicates that gas channeling has occurred. By combining the monitoring results of injection wells, production wells, and long core displacement experiments, a chart is generated to identify gas channeling. In the step of sampling well fluids from production wells to conduct long core displacement experiments, after saturating the long core model with formation water and formation oil under the target reservoir formation temperature and formation pressure, horizontal or vertical gas injection displacement experiments are directly carried out. In the step of sampling well fluids from the production well to conduct long core displacement experiments, the produced oil and gas volume is collected and measured for every 0.1 HCPV injected, and the changes in the gas injection equipment readings, injection pressure, confining pressure, and back pressure are recorded. The experiment ends when oil production ceases. Several samples of produced oil and gas are collected before and after the gas injection breakthrough. Before sampling the well fluid from the production well, the composition of the injection medium and the injection pressure of the injection well are monitored, as well as the production output, gas-oil ratio and production pressure of the production well are monitored. In the step of sampling well fluid from the production well to conduct long core displacement experiments, the gas propulsion speed during the experiment is controlled to be consistent with the gas propulsion speed during the actual gas injection development process in the field; the injected gas medium is configured according to the actual gas source composition of the oilfield. In the step of conducting long core displacement experiments by sampling well fluid from the production well, the materials used in the long core displacement experiments include: Cores: The actual cores taken from the target layer of the oil well in the reservoir are numbered, trimmed, and arranged in a mixed and average manner to form a long core group. The cores are connected with filter paper, sealed with Teflon heat shrink tubing, and then put into fluororubber tubes. Formation oil and injected hydrocarbon gas: The combined injection station uses reservoir-mixed formation oil and standard reservoir gas; Simulated formation water: using the formation water salinity recorded in the data; Analysis of the results of long core displacement experiments includes: 1) Considering the different mass transfer capabilities of different crude oil components and injected gas, the produced fluid is divided into several pseudo-components: C1+N2, C2~C6, C7~C16, and C17+. 2) During the stage of increasing and stabilizing seepage resistance, the content of each component segment at the producing end does not change significantly, and is close to the component distribution of formation oil; when seepage resistance begins to decrease, the content of C17+ component at the producing end decreases, while other components increase slightly; when the injected gas breaks through, the content of C1+N2 and C2~C6 components at the producing end increases rapidly, while the content of C7+ component decreases rapidly. The gas channeling discrimination method for reservoir gas injection development studies the displacement characteristics and the variation law of produced fluid composition through indoor experiments and field studies. It systematically analyzes the variation law of seepage resistance, produced end component content, gas-oil ratio and recovery degree, and forms discrimination charts for each stage of gas channeling to support the judgment of gas channeling and control timing in oilfield gas injection production.

2. The method for identifying gas channeling during reservoir gas injection development according to claim 1, characterized in that: The well fluid sample is taken 1 to 3 times per month.

3. The method for identifying gas channeling during reservoir gas injection development according to claim 1, characterized in that: In the step of sampling well fluid from the production well to conduct a long core displacement experiment, the preparation for the long core displacement experiment is first carried out according to the following steps: 1) When assembling the cores in sequence, add multiple layers of filter paper between the cores; 2) After the core is assembled, temperature and pressure tests are carried out according to the maximum pressure and temperature designed in the experiment to confirm that the model has no leakage.

4. The method for identifying gas channeling during reservoir gas injection development according to claim 3, characterized in that, The specific steps for conducting long core displacement experiments by sampling well fluid from production wells include: 1) Use methanol to clean the water in the core and petroleum ether to clean the oil in the core until the produced fluid is clear and transparent again. Finally, blow it dry with nitrogen and vacuum it. 2) Under formation temperature and pressure, the core is first saturated with water and then with oil, and after saturation, it is left to age statically. 3) Adjust the model orientation according to the dip angle of the strata; 4) Maintain outlet pressure and implement gas injection for displacement until the gas content reaches 100% and then end the displacement process; 5) Collect several samples of produced oil and gas before and after the breakthrough of the injected gas medium, and perform component composition analysis on each.

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