A shale gas well partition seepage production system optimization device and method

Abstract

The application discloses a shale gas well partition seepage production system optimization device and method, relates to the technical field of shale gas reservoir recovery improvement development, and comprises a plurality of high-temperature and high-pressure core clamps with confining pressure devices, which are respectively provided with cores of different partitions in a reservoir, are connected in series by pipelines between the core clamps, and are all provided with pressure gauges between the core clamps and at the head and tail ends. The pressure gauges at the head end are sequentially connected with a liquid flowmeter, a three-way valve, a back pressure valve, a metal horizontal wellbore and a gas flowmeter through pipelines. The three-way valve is connected with a fracturing fluid intermediate container through a pipeline, the fracturing fluid intermediate container is connected with a high-pressure displacement pump II through a pipeline. The pressure gauges at the tail end are connected with a gas source intermediate container and a liquid recovery device through pipelines, and the gas source intermediate container is connected with a high-pressure displacement pump III through a pipeline. The method and device can be used for studying the production and pressure drop distribution under different production systems, and can provide a reference for the development of shale gas reservoirs according to the actual production conditions of the gas reservoirs.

Description

Technical Field

[0001] This invention relates to the field of enhanced oil recovery technology for shale gas reservoirs, specifically to a device and method for optimizing the zoned seepage production regime of shale gas wells, applicable to the development of low-porosity, low-permeability shale gas reservoirs requiring hydraulic fracturing. Background Technology

[0002] my country's shale gas reservoirs are mainly distributed in the Sichuan Basin, Ordos Basin, Guizhou-Hunan region, eastern Chongqing-western Hubei region, and Tarim Basin. Most gas-producing shale formations are widely distributed, thick, and generally gas-bearing, enabling shale gas wells to produce gas stably over long periods. However, shale gas reservoirs have low permeability, making extraction difficult. The primary extraction method for these reservoirs is horizontal well fracturing. Controlling the production pressure differential is a major challenge. Too low a production pressure differential leads to low production capacity and poor economic returns, while too high a pressure differential can cause reservoir damage and stress sensitivity, resulting in a sharp decline in production capacity and affecting the final recovery rate. Therefore, designing an optimized production system and method is extremely important. Summary of the Invention

[0003] The regional flowback characteristics after reservoir fracturing are difficult to study using a single core sample. To overcome the shortcomings of existing technologies, this invention connects core samples representing different regions of the reservoir to form a multi-core, integrated, multi-dimensional experimental device for simulating actual gas and liquid production processes. This invention is characterized by its simple operation and precise measurement. Using this method, a process for studying the distribution of production and pressure drop under different production regimes can be established, providing a reference for shale gas reservoir development based on actual gas reservoir production conditions.

[0004] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0005] The first aspect of this invention provides a device for optimizing the zonal seepage production system of shale gas wells, comprising multiple high-temperature and high-pressure core holders equipped with confining pressure devices, each holding a core from a different zone of the reservoir. The core holders are connected in series by pipelines, and pressure gauges are installed between each core holder and at both ends. At the beginning, the pressure gauge is connected sequentially to a liquid flow meter, a three-way valve, a back pressure valve, a metal horizontal wellbore, and a gas flow meter via pipelines. The back pressure valve is connected to a nitrogen intermediate container via a pipeline, and the nitrogen intermediate container is connected to a high-pressure displacement pump I. The three-way valve is connected to a fracturing fluid intermediate container via a pipeline, and the fracturing fluid intermediate container is connected to a high-pressure displacement pump II via a pipeline. At the end, the pressure gauge is connected to a gas source intermediate container and a liquid recovery device via pipelines, and the gas source intermediate container is connected to a high-pressure displacement pump III via a pipeline.

[0006] Furthermore, the confining pressure device includes valves and a high-pressure pump. Pipelines are installed on each core holder for parallel connection and are connected to the valves and the high-pressure pump.

[0007] Furthermore, the core samples include matrix shale cores, shale cores with microfractures, shale cores with hydraulic fractures, and shale cores with hydraulic fractures and proppant filling.

[0008] Furthermore, the liquid recovery device is a test tube.

[0009] A second aspect of this invention provides a method for optimizing the zoned seepage production regime of shale gas wells, comprising the following steps:

[0010] Step 1, Core preparation: Load the cores into the respective core holders;

[0011] Step 2, Fluid preparation: Load the fracturing fluid into the fracturing fluid intermediate container, and compress a natural gas sample from the actual natural gas reservoir into the gas source intermediate container;

[0012] Step 3: Connect the experimental procedures: Connect the experimental procedures according to the experimental flowchart and check the airtightness;

[0013] Step 4: Vacuuming: Vacuum the pipelines, valves, and core holders;

[0014] Step 5: Simulating the core saturation fracturing fluid process during fracturing: First, set the confining pressure using the confining pressure device, then start the high-pressure displacement pump II to pressurize. The fracturing fluid flows in direction one, i.e., the fracturing fluid flows from the middle container of the fracturing fluid towards the liquid recovery device to carry out the fracturing fluid saturation process. When liquid is detected at the fluid detection outlet, record the liquid volume. When the outflow remains constant, slowly reduce the pressure at the inlet of the core holder along direction one to atmospheric pressure to stop saturation.

[0015] Step 6: Simulate the fracturing fluid flowback process of gas well production: First, set the confining pressure through the confining pressure device. Gas is injected from direction two, that is, from the gas source intermediate container to the metal horizontal wellbore. Along the core holder inlet at direction two, the gas source pressure is set to 35MPa, and the outlet pressure is gradually reduced according to the different production system schemes initially set.

[0016] Step 7, Data Recording: Record the readings of each pressure gauge and the outlet gas-liquid flow rate. After the pressure inside the core holder drops to atmospheric pressure, remove the core.

[0017] Step 8: Simulate different production pressure reduction regimes: Weigh the core, dry it, and repeat the above experimental process by changing the regime in turn;

[0018] Step 9: Data Analysis and Processing: Record the measurement results of the gas-liquid flow meter and the reading of the pressure gauge, compare the gas production, liquid production and pressure drop distribution of the three different pressure drop schemes, and preliminarily select the better pressure drop scheme.

[0019] Step 10: Based on the initially selected scheme, further refine the production pressure difference with an accuracy of 1 MPa, repeat the experimental steps to analyze the results, and determine the optimal pressure drop scheme more accurately.

[0020] Further steps include the following: In step 1, before loading the core into the core holder, the core must first be dried at 105°C for 48 hours until its quality does not change.

[0021] Further steps include the following: In step 2, the natural gas sample contains helium, nitrogen, carbon dioxide, hydrogen sulfide, and methane.

[0022] Furthermore, in step 6, the production schedule is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 15 hours, and production continues for another 35 hours.

[0023] Furthermore, in step 6, the production schedule is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 30 hours, and production continues for another 20 hours.

[0024] Furthermore, in step 6, the production system plan is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 50 hours.

[0025] Further steps include the following: In steps 5 and 6, the confining pressure is set to 50 MPa.

[0026] The beneficial effects of this invention are as follows:

[0027] 1. This invention, based on a shale gas well zoned seepage production regime optimization device, effectively simulates the flow of fluids in the core of an actual reservoir. It can fully demonstrate the different seepage characteristics of each zone after hydraulic fracturing of a shale gas reservoir, and set pressure drop schemes for different production regimes to achieve the purpose of optimizing the production regime. It can effectively guide the optimization of shale gas production regimes, on the one hand, it can extend the stable production time of shale gas, and on the other hand, it reveals the mechanism of optimizing the production regime of shale gas reservoirs, which can effectively improve the final recovery rate of shale gas reservoirs and improve the overall development effect of shale gas.

[0028] 2. This device and method can be used to optimize the production regime during the flowback and extraction stages. Based on the actual production conditions of the gas reservoir, a suitable production pressure differential can be selected, providing guidance for determining the optimal production regime for shale gas reservoirs and improving the final recovery rate of shale gas reservoirs. Attached Figure Description

[0029] Figure 1 A schematic diagram of the experimental process for an optimization device for zoned seepage production regime of shale gas wells provided in an embodiment of the present invention;

[0030] Figure 2 A graph showing the cumulative gas production over time provided in an embodiment of the present invention;

[0031] Figure 3 A diagram showing the pressure versus time relationship in Scheme 1 provided by an embodiment of the present invention;

[0032] Figure 4 The pressure-time relationship diagram of Scheme 2 provided in the embodiment of the present invention;

[0033] Figure 5 The pressure-time relationship diagram for Scheme 3 provided in the embodiment of the present invention;

[0034] Reference numerals: 1-Gas source intermediate container, 2-Core holder, 3-Core, 4-Pressure gauge, 5-Back pressure valve, 6-Fracturing fluid intermediate container, 7-High-pressure displacement pump I, 8-High-pressure pump, 9-Valve, 10-Metal horizontal wellbore, 11-Gas flow meter, 12-Liquid flow meter, 13-Test tube, 14-Three-way valve, 15-Nitrogen intermediate container, 16-High-pressure displacement pump II, 17-High-pressure displacement pump III. Detailed Implementation

[0035] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0036] Example 1

[0037] The first aspect of this invention provides a device for optimizing the zonal seepage production system of shale gas wells, comprising multiple high-temperature and high-pressure core holders 2 equipped with confining pressure devices, each holding a core from a different zone of the reservoir. The core holders 2 are connected in series by pipelines, and pressure gauges 4 are installed between each core holder 2 and at both ends. At the beginning of the pressure gauge 4, a liquid flow meter 12, a three-way valve 14, a back pressure valve 5, a metal horizontal wellbore 10, and a gas flow meter 11 are connected in sequence by pipelines. The back pressure valve 5 is connected to a nitrogen intermediate container 15 by pipelines, and the nitrogen intermediate container 15 is connected to a high-pressure displacement pump I7. The three-way valve 14 is connected to a fracturing fluid intermediate container 6 by pipelines, and the fracturing fluid intermediate container 6 is connected to a high-pressure displacement pump II16 by pipelines. At the end of the pressure gauge 4, a gas source intermediate container 1 and a liquid recovery device are connected by pipelines, and the gas source intermediate container 1 is connected to a high-pressure displacement pump III17 by pipelines.

[0038] In this embodiment, the confining pressure device includes a valve 9 and a high-pressure pump 8. Each core holder 2 is provided with pipelines for parallel connection, and the valve 9 and the high-pressure pump 8 are connected.

[0039] Core 3 includes a matrix shale core, a shale core with microfractures, a shale core with hydraulic fractures, and a shale core with hydraulic fractures and filled with proppant.

[0040] Furthermore, the liquid recovery device is test tube 13.

[0041] In this embodiment, multiple high-temperature and high-pressure core holders 2 equipped with confining pressure devices are included to simulate and reproduce the formation temperature and pressure environment. Each core holder 2 contains cores 3 from different zones of the same reservoir, including matrix shale cores, shale cores with microfractures, shale cores with hydraulic fractures, and shale cores with hydraulic fractures and filled with proppant, which can simulate near-wellbore and far-wellbore reservoir zones. The high-pressure displacement pump II16 is used to displace the liquid in the fracturing fluid intermediate container 6 to simulate fracturing fluid saturation of the reservoir core, and then the high-pressure displacement pump III17 is used to displace the gas in the gas source intermediate container 1 to simulate the entire process of reservoir core depletion production. Pressure gauges 4 are installed between each core holder 2 and at both ends to measure the pressure along the process of core production and obtain pressure profiles. The outlet pressure is controlled by the back pressure valve 5, which connects the nitrogen intermediate container 15 and the high-pressure displacement pump I7 to simulate the pressure drop rate in actual production. During the experiment, the gas flow meter 11 is used to measure the gas volume, and the liquid flow meter 12 is used to measure the liquid volume to obtain the final cumulative gas production and cumulative liquid production.

[0042] During implementation, the core saturation fracturing fluid process is simulated as follows: First, confining pressure is set in each core holder 2 through the confining pressure device. Then, the high-pressure displacement pump II16 is started to pressurize and drive the fracturing fluid in the intermediate fracturing fluid container 6 to flow out of the intermediate fracturing fluid container 6. The fluid flows along the intermediate fracturing fluid container 6 towards the liquid recovery device, passes through each core holder 2, and undergoes the saturation fracturing fluid process. Finally, it flows to the liquid recovery device. When the liquid flow meter 12 at the fluid detection outlet detects the liquid, the liquid volume is recorded. When the outflow remains unchanged, the inlet pressure of the first core holder 2 is slowly reduced to atmospheric pressure to stop saturation.

[0043] Simulated fracturing fluid flowback process in gas well production: First, the confining pressure is set by the confining pressure device, the high-pressure displacement pump III17 is started to pressurize, and the gas is driven to flow out from the gas source intermediate container 1. The gas is injected along the gas source intermediate container 1 towards the metal horizontal wellbore 10. The gas passes through each core holder 2 and finally flows to the metal horizontal wellbore 10.

[0044] Example 2

[0045] This embodiment further elaborates and supplements the implementation of the present invention based on Embodiment 1.

[0046] A second aspect of this invention provides a method for optimizing the zoned seepage production regime of shale gas wells, comprising the following steps:

[0047] Step 1, Core preparation: Insert the core 3 into each core holder 2;

[0048] Step 2, Fluid preparation: Load fracturing fluid into fracturing fluid intermediate container 6, and compress natural gas samples from the actual natural gas reservoir into gas source intermediate container 1;

[0049] Step 3: Connect the experimental procedures: Connect the experimental procedures according to the experimental flowchart and check the airtightness;

[0050] Step 4, Vacuuming: Vacuum the pipeline, valve 9, and core holder 2;

[0051] Step 5: Simulating the core saturation fracturing fluid process during fracturing: First, set the confining pressure using the confining pressure device, then start the high-pressure displacement pump II16 to pressurize. The fracturing fluid flows in direction one, i.e., along the fracturing fluid intermediate container 6 towards the liquid recovery device to carry out the fracturing fluid saturation process. When liquid is detected at the fluid detection outlet, record the liquid volume. When the outflow remains constant, slowly reduce the inlet pressure of the core holder 2 along direction one to atmospheric pressure to stop saturation.

[0052] Step 6: Simulate the fracturing fluid flowback process during gas well production: First, set the confining pressure using a confining pressure device. Gas is injected from direction two, i.e., from the gas source intermediate container 1 into the metal horizontal wellbore 10. Along the inlet of the core holder 2 at direction two, the gas source pressure is set to 35MPa. The outlet pressure is gradually reduced according to the different production system schemes initially set below. The total production time is set to 6 days.

[0053] Option 1: Reduce the outlet pressure from 35MPa to 5MPa within 15 hours and continue production for another 35 hours;

[0054] Option 2: Reduce the outlet pressure from 35MPa to 5MPa within 30 hours and continue production for another 20 hours;

[0055] Option 3: Reduce the outlet pressure from 35MPa to 5MPa within 50 hours;

[0056] Step 7, Data Recording: Record the readings of each pressure gauge 4 and the outlet gas-liquid flow rate. After the pressure inside the core holder 2 drops to atmospheric pressure, remove the core 3.

[0057] Step 8: Simulate different production pressure reduction regimes: Weigh core 3, dry it, and repeat the above experimental process by changing the regime in turn;

[0058] Step 9, Data Analysis and Processing: Record the measurement results of the gas-liquid flow meter and the reading of pressure gauge 4, compare the gas production, liquid production and pressure drop distribution of the three different pressure drop schemes, and preliminarily select the better pressure drop scheme.

[0059] Step 10: Based on the initially selected scheme, further refine the production pressure difference with an accuracy of 1 MPa, repeat the experimental steps to analyze the results, and determine the optimal pressure drop scheme more accurately.

[0060] In this embodiment, the confining pressure is set to 50 MPa in steps 5 and 6.

[0061] In the implementation, the core saturation fracturing fluid process of the simulated fracturing process is as follows: First, confining pressure is set in each core holder 2 through the confining pressure device. Then, the high-pressure displacement pump II16 is started to pressurize, so that the fracturing fluid in the intermediate fracturing fluid container 6 flows in direction one, that is, from the intermediate fracturing fluid container 6 to the liquid recovery device to carry out the fracturing fluid saturation process. When the liquid flow meter 12 at the fluid detection outlet detects the liquid, the liquid volume is recorded. When the outflow volume remains unchanged, the inlet pressure of the core holder 2 in direction one is slowly reduced to atmospheric pressure to stop saturation.

[0062] Simulated fracturing fluid flowback process in gas well production: First, the confining pressure is set by the confining pressure device. Gas is injected from direction two, that is, from the gas source intermediate container 1 to the metal horizontal wellbore 10. Along the core holder 2 inlet at direction two, the gas source pressure is set to 35MPa, and the outlet pressure is gradually reduced according to the different production system schemes initially set.

[0063] Example 3

[0064] This embodiment further elaborates and supplements the implementation of the present invention based on Embodiment 1 or Embodiment 2.

[0065] In step 1, before loading core 3 into core holder 2, core 3 needs to be dried at 105℃ for 48 hours until its quality remains unchanged.

[0066] In step 2, the natural gas sample contains helium, nitrogen, carbon dioxide, hydrogen sulfide, and methane.

[0067] In step 6, the production schedule is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 15 hours, and production continues for another 35 hours.

[0068] In step 6, the production schedule is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 30 hours, and production continues for another 20 hours.

[0069] In step 6, the production schedule is as follows: the outlet pressure will be reduced from 35 MPa to 5 MPa within 50 hours.

[0070] Example 4

[0071] This embodiment further elaborates and supplements the implementation of the present invention based on Embodiment 1, Embodiment 2 or Embodiment 3.

[0072] The first aspect of this invention provides a device for optimizing the zoned seepage production regime of shale gas wells, such as... Figure 1 As shown, the system includes multiple high-temperature and high-pressure core holders 2 equipped with confining pressure devices, each containing cores from different zones of the reservoir. The core holders 2 are connected in series by pipelines, and pressure gauges 4 are installed between each core holder 2 and at both ends. At the beginning, pressure gauge 4 is connected in sequence to a liquid flow meter 12, a three-way valve 14, a back pressure valve 5, a metal horizontal wellbore 10, and a gas flow meter 11 via pipelines. The back pressure valve 5 is connected to a nitrogen intermediate container 15 via pipelines, and the nitrogen intermediate container 15 is connected to a high-pressure displacement pump I7. The three-way valve 14 is connected to a fracturing fluid intermediate container 6 via pipelines, and the fracturing fluid intermediate container 6 is connected to a high-pressure displacement pump II16 via pipelines. At the end, pressure gauge 4 is connected to a gas source intermediate container 1 and a liquid recovery device via pipelines, and the gas source intermediate container 1 is connected to a high-pressure displacement pump III17 via pipelines.

[0073] In this embodiment, the confining pressure device includes a valve 9 and a high-pressure pump 8. Each core holder 2 is provided with pipelines for parallel connection, and the valve 9 and the high-pressure pump 8 are connected.

[0074] Core 3 includes a matrix shale core, a shale core with microfractures, a shale core with hydraulic fractures, and a shale core with hydraulic fractures and filled with proppant.

[0075] Furthermore, the liquid recovery device is test tube 13.

[0076] A second aspect of this invention provides a method for optimizing the zoned seepage production regime of shale gas wells, comprising the following steps:

[0077] Step 1, Core Preparation: Before loading the shale cores with matrix, microfractured shale cores, hydraulically fractured shale cores, and hydraulically fractured shale cores filled with proppant into the core holder 2, the cores must first be dried at 105℃ for 48 hours until their mass remains unchanged; Figure 1 As shown, from right to left, the processed shale core with matrix is ​​placed into the first core holder 2, the shale core with microcracks is placed into the second core holder 2, the shale core with hydraulic fractures is placed into the third core holder 2, and the shale core with hydraulic fractures and filled with proppant is placed into the fourth core holder 2.

[0078] Step 2, Fluid preparation: Load fracturing fluid into fracturing fluid intermediate container 6, and compress natural gas samples from the actual natural gas reservoir into gas source intermediate container 1;

[0079] Table 1 Composition of natural gas samples

[0080] Components Content (mole fraction, %) helium 0.02 nitrogen 0.41 carbon dioxide 1.08 hydrogen sulfide ﹤0.01 methane 97.74 Ethane 0.71 propane 0.03

[0081] Step 3: Connect the experimental procedures: Connect the experimental procedures according to the experimental flowchart and check the airtightness;

[0082] Step 4, Vacuuming: Vacuum the pipeline, valve 9, and core holder 2;

[0083] Step 5: Simulating the core saturation fracturing fluid process during fracturing: First, set the confining pressure using the confining pressure device, then start the high-pressure displacement pump II16 to pressurize. The fracturing fluid flows in direction one, i.e., along the fracturing fluid intermediate container 6 towards the liquid recovery device to carry out the fracturing fluid saturation process. When liquid is detected at the fluid detection outlet, record the liquid volume. When the outflow remains constant, slowly reduce the inlet pressure of the core holder 2 along direction one to atmospheric pressure to stop saturation.

[0084] Step 6: Simulate the fracturing fluid flowback process of gas well production: First, set the confining pressure through the confining pressure device. Gas is injected from direction two, that is, from the gas source intermediate container 1 to the metal horizontal wellbore 10. Along the core holder 2 inlet at direction two, the gas source pressure is set to 35MPa, and the outlet pressure is gradually reduced according to the different production system schemes initially set.

[0085] Step 7, Data Recording: Record the readings of each pressure gauge 4 and the outlet gas-liquid flow rate. After the pressure inside the core holder 2 drops to atmospheric pressure, remove the core 3.

[0086] Step 8: Simulate different production pressure reduction regimes: Weigh the core, dry it, and repeat the above experimental process by changing the regime in turn;

[0087] Step 9, Data Analysis and Processing: Record the measurement results of the gas-liquid flow meter and the reading of pressure gauge 4, compare the gas production, liquid production and pressure drop distribution of the three different pressure drop schemes, and preliminarily select the better pressure drop scheme.

[0088] Table 2 shows the cumulative gas production over time.

[0089]

[0090] By comparing the gas production, liquid production, and pressure drop distribution in different zones of three different pressure drop schemes, after 50 hours of production, Scheme 3 had the highest cumulative gas production of 612 L. Figure 2 The trend shows that in the first 46 hours, the gas production of Option 3 was lower than that of Option 1 and Option 2, and then gradually exceeded that of Option 1 and then Option 2.

[0091] Table 3 Pressure Recording Data for Scheme 1

[0092] Time h P2 P3 P4 P5 0 35.3093 35.3093 35.3093 35.3093 0.3 30.6 30.8 31.4 35.3 1.2 28.1 28.4 29.2 35.3 2.4 25.7 25.8 27.1 35.3 3.7 23.5 23.7 25.2 35.3 4.9 21.8 21.9 23.8 35.3 6.4 20.0 20.1 22.3 35.3 7.9 18.0 18.1 20.7 35.3 9.1 16.8 16.8 19.7 35.3 10.3 15.3 15.4 18.6 35.3 11.5 13.9 13.9 17.5 35.3 12.6 12.4 12.5 16.5 35.3 13.5 10.3 10.3 14.6 35.3 14.5 8.3 8.5 13.4 35.3 15.5 6.9 7.1 12.3 35.3 17.5 7.0 7.2 11.7 35.3 19.6 7.0 7.2 11.7 35.3 21.8 7.0 7.2 11.7 35.3 23.9 7.0 7.2 11.7 35.3 25.9 7.0 7.2 11.7 35.3 28.0 7.0 7.2 11.7 35.3 30.3 7.0 7.2 11.7 35.3 32.6 7.0 7.2 11.7 35.3 34.6 7.0 7.2 11.7 35.3 36.7 7.0 7.2 11.7 35.3 39.9 7.0 7.2 11.7 35.3 43.3 7.0 7.2 11.7 35.3 46.8 7.0 7.2 11.7 35.3 48.6 7.0 7.2 11.7 35.3 51.7 7.0 7.2 11.7 35.3

[0093] Table 4 Pressure Recording Data for Scheme 2

[0094] Time h P2 P3 P4 P5 0 35.06108 35.06108 35.06108 35.06108 0.3 30.6 30.7 31.0 35.1 0.9 29.7 29.9 30.3 35.1 2.5 27.4 27.5 28.3 35.1 4.0 25.1 25.3 26.4 35.1 5.4 23.4 23.5 24.8 35.1 6.9 21.8 21.9 23.5 35.1 8.8 20.1 20.2 22.0 35.1 10.2 18.8 18.9 21.0 35.1 11.6 17.6 17.6 19.9 35.1 13.1 16.4 16.4 18.9 35.1 14.6 15.2 15.2 18.0 35.1 16.3 14.0 14.0 16.9 35.1 17.7 13.0 13.1 16.1 35.1 19.3 12.2 12.2 15.4 35.1 20.9 11.4 11.5 14.9 35.1 22.5 10.7 10.8 14.3 35.1 24.5 9.8 9.9 13.6 35.1 26.0 9.1 9.3 13.2 35.1 27.6 8.5 8.7 12.8 35.1 29.2 7.8 8.0 12.4 35.1 31.0 7.3 7.4 11.8 35.1 33.4 7.3 7.4 11.8 35.1 36.1 7.3 7.4 11.8 35.1 38.0 7.3 7.4 11.7 35.1 40.2 7.3 7.4 11.7 35.1 42.6 7.3 7.4 11.7 35.1 45.0 7.3 7.4 11.7 35.1 48.4 7.3 7.4 11.7 35.1 51.5 7.3 7.4 11.7 35.1

[0095] Table 5 Pressure Recording Data for Scheme 3

[0096]

[0097]

[0098] Based on the pressure data recorded from the three schemes, it can be seen that the pressure difference between the inlet and outlet of core 3, which has the highest permeability, is the smallest, while the pressure difference between the inlet and outlet of core 3, which has the lowest permeability, is the largest. A line graph is shown below. Figure 3 , Figure 4 , Figure 5 As shown; analyzing its mechanism, Scheme 3 controls the pressure drop the slowest, which can effectively reduce the negative impact of stress sensitivity on the closure of the fracture in core 3, thus slowing down the decrease in its permeability.

[0099] Step 10: Based on the initially selected scheme, further refine the production pressure difference with an accuracy of 1 MPa, repeat the experimental steps to analyze the results, and determine the optimal pressure drop scheme more accurately.

[0100] The above embodiments of the present invention demonstrate the effectiveness of the production system optimization method based on the partitioned seepage experimental device in actual production. It can intuitively and quantitatively analyze the impact of production pressure difference, which provides valuable information for subsequent shale gas management and development.

[0101] This invention, based on a designed experimental apparatus, effectively simulates the fluid flow in core sample 3 of an actual reservoir. It fully demonstrates the differential seepage characteristics of different zones after hydraulic fracturing in shale gas reservoirs, and sets pressure drop schemes for different production regimes to achieve optimal production regime optimization. This effectively guides the optimization of shale gas production regimes, extending the stable production period and revealing the mechanism of optimizing shale gas reservoir production regimes. Ultimately, it can effectively improve the final recovery rate of shale gas reservoirs and enhance the overall development effect of shale gas.

[0102] This invention is applicable to the development of low-porosity and low-permeability shale gas reservoirs requiring hydraulic fracturing. It features simple operation and precise measurement. Using this device and method, the production regime can be optimized during the flowback and extraction stages. Based on the actual production conditions of the gas reservoir, a suitable production pressure differential can be selected, providing guidance for determining the optimal production regime for shale gas reservoirs and improving the ultimate recovery rate (EUR) of shale gas reservoirs. This invention plays a crucial supporting role in the large-scale development and improved recovery rate of shale gas in Sichuan and Chongqing.

Claims

1. A device for optimizing the zoned seepage production system of shale gas wells, characterized in that: The system includes multiple high-temperature and high-pressure core holders (2) equipped with confining pressure devices, each containing cores (3) from different zones of the reservoir. The core holders (2) are connected in series by pipelines, and pressure gauges (4) are installed between each core holder (2) and at both ends. At the pressure gauge (4) at the beginning, a liquid flow meter (12), a three-way valve (14), a back pressure valve (5), a metal horizontal wellbore (10), and a gas flow meter (11) are connected in sequence by pipelines. The back pressure valve (5) is connected to a nitrogen intermediate container (15) by pipelines, and the nitrogen intermediate container (15) is connected to a high-pressure displacement pump. (7); The three-way valve (14) is connected to the fracturing fluid intermediate container (6) via a pipeline, and the fracturing fluid intermediate container (6) is connected to the high-pressure displacement pump via a pipeline. (16); The pressure gauge (4) at the tail end is connected to the gas source intermediate container (1) and the liquid recovery device through a pipeline. The gas source intermediate container (1) is connected to the high-pressure displacement pump through a pipeline. (17).

2. The shale gas well zoned seepage production system optimization device as described in claim 1, characterized in that: The confining pressure device includes a valve (9) and a high-pressure pump (8). Each core holder (2) is equipped with a pipeline for parallel connection and connected to the valve (9) and the high-pressure pump (8).

3. The shale gas well zoned seepage control pressure production system optimization device as described in claim 2, characterized in that: Cores (3) include matrix shale cores, shale cores with microcracks, shale cores with hydraulic fractures, and shale cores with hydraulic fractures and filled with proppant.

4. The shale gas well zoned seepage control pressure production system optimization device as described in claim 3, characterized in that: The liquid recovery device is a test tube (13).

5. A method for optimizing the zoned seepage production regime of shale gas wells, characterized in that: Includes the following steps: Step 1, Core preparation: Insert the core (3) into each core holder (2); Step 2, Fluid preparation: Load fracturing fluid into the fracturing fluid intermediate container (6), and compress natural gas samples from the actual natural gas reservoir into the gas source intermediate container (1). Step 3: Connect the experimental procedures: Connect the experimental procedures according to the experimental flowchart and check the airtightness; Step 4, Vacuuming: Vacuum the pipeline, valves (9), and core holder (2); Step 5: Simulating the core saturation fracturing fluid process during hydraulic fracturing: First, set the confining pressure using a confining pressure device, then start the high-pressure displacement pump. (16) Pressurize, the fracturing fluid flows in one direction, that is, the fracturing fluid flows in the middle container (6) of the fracturing fluid towards the liquid recovery device to carry out the saturation process of the fracturing fluid. When the fluid is detected at the fluid detection outlet, record the liquid volume. When the outflow volume remains unchanged, slowly reduce the inlet pressure of the core holder (2) in one direction to atmospheric pressure to stop saturation. Step 6: Simulate the fracturing fluid flowback process of gas well production: First, set the confining pressure through the confining pressure device. Gas is injected from direction two, that is, from the gas source intermediate container (1) to the metal horizontal wellbore (10). The gas source pressure is set to 35MPa at the inlet of the core holder (2) at direction two, and the outlet pressure is gradually reduced according to the different production system schemes initially set. Step 7, Data Recording: Record the readings of each pressure gauge (4) and the outlet gas-liquid flow rate. After the pressure inside the core holder (2) drops to atmospheric pressure, remove the core (3). Step 8: Simulate different production pressure reduction regimes: Weigh the core (3), dry it, and repeat the above experimental process by changing the scheme in turn; Step 9, Data Analysis and Processing: Record the measurement results of the gas-liquid flow meter and the reading of the pressure gauge (4), compare the gas production, liquid production and pressure drop distribution of the three different pressure drop schemes, and preliminarily select the better pressure drop scheme. Step 10: Based on the initially selected scheme, further refine the production pressure difference with an accuracy of 1 MPa, repeat the experimental steps to analyze the results, and determine the optimal pressure drop scheme more accurately.

6. The method for optimizing the zonal seepage production regime of shale gas wells as described in claim 5, characterized in that: The process includes the following steps: In step 1, before loading the core (3) into the core holder (2), the core (3) must first be dried at 105°C for 48 hours until its quality does not change.

7. The method for optimizing the zonal seepage production system of shale gas wells as described in claim 5, characterized in that: The process includes the following steps: In step 2, the natural gas sample contains helium, nitrogen, carbon dioxide, hydrogen sulfide, and methane.

8. The method for optimizing the zonal seepage production system of shale gas wells as described in claim 5, characterized in that: In step 6, the production schedule is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 15 hours, and production continues for another 35 hours.

9. The method for optimizing the zonal seepage production system of shale gas wells as described in claim 8, characterized in that: In step 6, the production schedule is as follows: the outlet pressure is reduced from 35MPa to 5MPa within 30 hours, and production continues for another 20 hours.

10. The method for optimizing the zonal seepage production system of shale gas wells as described in claim 9, characterized in that: In step 6, the production schedule is as follows: the outlet pressure will be reduced from 35 MPa to 5 MPa within 50 hours.

11. The method for optimizing the zonal seepage production regime of shale gas wells as described in claim 5, characterized in that: The process includes the following steps: In steps 5 and 6, the confining pressure is set to 50 MPa.

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