In-situ analysis device and method for imbibition and retention characteristics of coal shale fracturing fluid

Abstract

The invention relates to an in-situ analysis device and method for imbibition and retention characteristics of coal shale fracturing fluid. The device comprises a high-pressure gas drive system, a core holder, a fracturing fluid conveying and injecting system, a precise weighing device and a liquid recovery device, and the high-pressure gas drive system and the fracturing fluid conveying and injecting system are connected with an inlet in one end of the core holder through pipelines respectively. A first liquid chromatograph is connected in series on a pipeline for connecting the fracturing fluid conveying and injecting system and the rock core holder, an outlet at the other end of the rock core holder is connected with a weighing container placed on precise weighing equipment through a pipeline, the bottom of the weighing container is connected with a liquid recovery device, and a second liquid chromatograph is connected in series on the pipeline; a heating device and a low-field nuclear magnetic resonance spectrometer are arranged outside the core holder, and an inner cavity of the core holder is connected with an annular pressure pump. The method has the advantages that the change of chemical components of the fracturing fluid in the sample before and after imbibition and reverse drainage of the fracturing fluid can be accurately and quantitatively analyzed.

Description

Technical Field

[0001] The present invention relates to the field of unconventional natural gas exploration and development, and in particular to an in-situ analysis device and method for the imbibition and retention characteristics of coal shale fracturing fluid. Background Art

[0002] As typical unconventional natural gas resources, shale gas and coalbed methane play an increasingly important role in the global energy supply. Due to the low porosity and low permeability of coal shale, traditional mining technology cannot effectively extract natural gas from the rock formation. Therefore, hydraulic fracturing technology has become the key to achieving commercial mining. Although hydraulic fracturing technology has greatly promoted the development of shale gas and coalbed methane, this technology is also accompanied by many environmental problems and technical challenges, especially the imbibition and retention of fracturing fluid.

[0003] When the fracturing fluid is absorbed and retained in the rock fractures, the part that fails to return to the surface effectively will occupy the fracture space and reduce the effective flow channel in the fracture. This phenomenon reduces the flow conductivity of the fracture, which directly affects the fluidity and ultimate recovery rate of natural gas. In addition, some components in the fracturing fluid, such as high molecular polymers and chemical additives, will form retention areas in the rock pores. These areas not only reduce the effective permeability of the rock, but may also change the physical structure of the rock through chemical reactions, further reducing the extraction efficiency of oil and gas. Therefore, effective management and optimization of the use of fracturing fluid to reduce its absorption and retention are the key to improving oil and gas extraction efficiency and reducing operating costs. In addition, the residual chemicals in the fracturing fluid may cause long-term environmental impacts on the formation. At present, there is a lack of devices and related technologies on the market that can monitor the dynamics of fracturing fluid absorption and retention in real time.

[0004] Therefore, there is an urgent need to develop an in-situ analysis device and method for the imbibition and retention characteristics of coal shale fracturing fluid to monitor and analyze the imbibition and retention behavior of fracturing fluid in rock formations in real time, so as to meet the urgent needs of the shale gas and coalbed methane industries for efficient mining technology. Summary of the invention

[0005] The technical problem to be solved by the present invention is to provide an in-situ analysis device and method for the imbibition and retention characteristics of coal shale fracturing fluid, which effectively overcomes the defects of the prior art.

[0006] The technical solution of the present invention to solve the above technical problems is as follows:

[0007] An in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid comprises a high-pressure gas drive system, a core holder, a fracturing fluid delivery and injection system, a precision weighing device and a liquid recovery device, wherein the high-pressure gas drive system and the fracturing fluid delivery and injection system are respectively connected to an inlet at one end of the core holder through pipelines, and a first liquid chromatograph is connected in series to the pipeline connecting the fracturing fluid delivery and injection system and the core holder, an outlet at the other end of the core holder is connected to a weighing container placed on the precision weighing device through a pipeline, a liquid outlet is provided at the bottom of the weighing container, the liquid outlet is connected to the liquid recovery device through a pipeline, and a second liquid chromatograph is connected in series to the pipeline, a heating device for heating the inside of the core holder and a low-field nuclear magnetic resonance instrument for scanning and analyzing the core sample inside the core holder are externally provided, and an annular pressure pump is connected to the inner cavity of the core holder.

[0008] Based on the above technical solution, the present invention can also be improved as follows.

[0009] Furthermore, the high-pressure gas drive system includes a high-pressure gas source and a first stop valve, a filter, a pressure regulating valve and an air intake valve which are connected in series with the outlet of the high-pressure gas source through a pipeline. A first pressure gauge is provided on the pipe section between the first stop valve and the filter, and a second pressure gauge is provided on the pipe section between the pressure regulating valve and the air intake valve.

[0010] Furthermore, the above-mentioned fracturing fluid delivery and injection system includes a liquid container and a second stop valve, a constant pressure and constant speed pump and the above-mentioned first liquid chromatograph which are connected in series with the outlet of the above-mentioned liquid container through a pipeline. The second stop valve and the liquid inlet valve are respectively provided on the pipe section of the pipeline corresponding to the outlet of the above-mentioned liquid container and between the above-mentioned first liquid chromatograph and the core clamp.

[0011] Furthermore, one end inlet of the core holder is connected to a four-way valve, the high-pressure gas drive system and the fracturing fluid delivery and injection system are respectively connected to two interfaces of the four-way valve through pipelines, and the remaining interface of the four-way valve is connected to a third pressure gauge.

[0012] Furthermore, the above-mentioned precision weighing equipment includes a precision balance.

[0013] Furthermore, the heating device is an electric heating tube arranged outside the core holder.

[0014] Furthermore, the heating device is a heating chamber arranged outside the core holder.

[0015] Furthermore, it also includes a computer, which is connected to the first liquid chromatograph, the second liquid chromatograph and the heating device.

[0016] Furthermore, it also includes a gas recovery device, a three-way valve is connected in series on the pipeline connecting the liquid outlet and the liquid recovery device, the remaining interface of the three-way valve is connected to the gas recovery device through a pipeline, and a gas flow meter is provided on the pipeline.

[0017] The beneficial effects of the present invention are: the device is reasonably designed, can test the imbibition and backflow dynamics of fracturing fluid in the complex pore system of coal shale in real time online, and can accurately quantify the changes in the chemical composition of the fracturing fluid in the sample before and after the imbibition and backflow of the fracturing fluid.

[0018] A method for in-situ analysis of imbibition and retention characteristics of coal shale fracturing fluid is also provided, comprising the following steps:

[0019] Step 1: preparing a core sample of set size and porosity;

[0020] Step 2: Dry the core sample and put it into the core holder;

[0021] Step 3: preparing the fracturing fluid and loading it into the fracturing fluid delivery and injection system;

[0022] Step 4: Turn on the heating device to heat the core sample in the core holder to a set simulated actual formation temperature;

[0023] Step 5: Start the annular pressure pump to adjust the confining pressure in the core holder to achieve the set pressure condition matching the actual reservoir;

[0024] Step 6: Turn on the low-field nuclear magnetic resonance instrument to scan and measure the core sample to obtain the T relaxation time distribution, and analyze the distribution inside the rock matrix pores based on the data;

[0025] Step 7: Analyze the chemical composition and substance concentration of the fracturing fluid by a first liquid chromatograph to obtain baseline chemical data of the fracturing fluid before injection;

[0026] Step 8: Using the fracturing fluid delivery and injection system to maintain a set flow rate and pressure to inject into the core holder, and conducting a set period of coal rock core fracturing fluid imbibition experiment to obtain a coal rock core saturated with fracturing fluid;

[0027] Step 9: Use a high-pressure gas drive system to inject high-pressure gas into the core holder to displace the fracturing fluid in the core holder until no liquid flows out of the core holder outlet, and collect and weigh the fracturing fluid in a weighing container to obtain the weight of the fracturing fluid discharged during the experiment. At the same time, during the injection of high-pressure gas, use a low-field nuclear magnetic resonance instrument to measure the T2 relaxation time at different gas drive times to evaluate the pore structure and residual fluid state in the core;

[0028] Step 10: Perform secondary analysis on the removed fracturing fluid using a second liquid chromatograph, measure the T relaxation time at different gas drive times to evaluate the pore structure and residual fluid state in the core sample, and then compare it with the first analysis result obtained in step 7 to analyze the changes in chemical composition and concentration before and after passing through the core sample. After analysis, store the collected fracturing fluid in a liquid recovery device;

[0029] Step 11: Calculate the imbibition rate S of the fracturing fluid of the core sample using Formula 1, and calculate the retention rate R of the fracturing fluid under different gas drive time conditions using Formula 2, as follows:

[0030] Formula 1

[0031] Formula 2

[0032] Among them, V f is the total volume of fracturing fluid injected into the core; V r is the volume of fracturing fluid discharged from the core BRIEF DESCRIPTION OF THE DRAWINGS

[0033] Figure 1 It is a structural schematic diagram of the in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid of the present invention;

[0034] Figure 2 This is a flow chart of the in-situ analysis method of the coal shale fracturing fluid imbibition and retention characteristics of the present invention;

[0035] Figure 3 This is a curve diagram showing the relationship between the fracturing fluid retention rate and the gas drive time of the coal rock sample in the present invention.

[0036] In the accompanying drawings, the components represented by the reference numerals are listed as follows:

[0037] 1. High-pressure gas source; 2. Liquid container; 3. First stop valve; 4. First pressure gauge; 5. Filter; 6. Pressure regulating valve; 7. Second pressure gauge; 8. Inlet valve; 9. Computer; 10. Second stop valve; 11. Constant pressure and speed pump; 12. First liquid chromatograph; 13. Liquid inlet valve; 14. Third pressure gauge; 15. Heating device; 16. Core holder; 17. Annular pressure pump; 18. Precision weighing equipment; 19. Low-field nuclear magnetic resonance instrument; 20. Three-way valve; 21. Gas flow meter; 22. Gas recovery device; 23. Second liquid chromatograph; 24. Liquid recovery device. DETAILED DESCRIPTION

[0038] The principles and features of the present invention are described below in conjunction with the accompanying drawings. The examples given are only used to explain the present invention and are not used to limit the scope of the present invention.

[0039] Example

[0040] like Figure 1 As shown, the in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid in this embodiment includes a high-pressure gas drive system, a core clamp 16, a fracturing fluid delivery and injection system, a precision weighing device 18 and a liquid recovery device 24, the high-pressure gas drive system and the fracturing fluid delivery and injection system are respectively connected to one end inlet of the core clamp 16 through pipelines, and a first liquid chromatograph 12 is connected in series to the pipeline connecting the fracturing fluid delivery and injection system and the core clamp 16, the other end outlet of the core clamp 16 is connected to a weighing container placed on the precision weighing device 18 through a pipeline, a liquid outlet is provided at the bottom of the weighing container, the liquid outlet is connected to the liquid recovery device 24 through a pipeline, and a second liquid chromatograph 23 is connected in series to the pipeline, the core clamp 16 is externally provided with a heating device 15 for heating the inside thereof and a low-field nuclear magnetic resonance instrument 19 for scanning and analyzing the core sample inside thereof, and the inner cavity of the core clamp 16 is connected to a ring pressure pump 17.

[0041] like Figure 2 and 3 As shown, the method for analyzing the coal shale fracturing fluid in-situ analysis device for imbibition and retention characteristics of the present embodiment includes the following steps:

[0042] Step 1: Prepare core samples of set size and porosity. Specifically, select regular columnar coal rock samples from the target coal seam reservoir. These samples have the following basic characteristics: diameter is about 25.25mm, length is 35.50mm, dry weight is 45.92g, porosity is 4.12%

[0043] Step 2: Dry the core sample and put it into the core holder 16. Specifically, place the core sample (coal rock sample) in a constant temperature oven, set the temperature to 105°C, and continue drying for 24 hours. Remove the free water in the core to ensure that the sample is dry during the nuclear magnetic resonance scanning, thereby reducing the interference of moisture on the scanning results. After drying, cool the sample to room temperature in a dryer to avoid the influence of humidity in the air on the weight of the sample; after this step, check the connection and air tightness of the experimental device;

[0044] Step three, prepare the fracturing fluid and load it into the fracturing fluid delivery and injection system. Specifically, the process of preparing the fracturing fluid is: select water as the base fracturing fluid medium. On this basis, add 0.5% carboxymethyl cellulose as a thickener to increase the viscosity of the fracturing fluid, thereby improving the sand carrying capacity in the cracks. At the same time, add 0.1% preservative and 0.2% biological agent to inhibit microbial growth and prevent the fracturing fluid from deteriorating. In order to control the pH value of the fracturing fluid and reduce the tension on the rock surface, add 0.05% hydrochloric acid and 0.1% non-ionic surfactant. These additives need to be pre-mixed in small batches before adding to ensure that they are fully dissolved and evenly distributed. When mixing, they should be added slowly to the mixer to avoid generating too many bubbles and ensure that the additives are completely dissolved. Finally, transfer the prepared fracturing fluid to a clean storage container, let it stand to allow the bubbles to release, and perform a final stir before use to ensure its uniformity and stability;

[0045] Step 4: Turn on the heating device 15 to heat the core sample in the core holder 16 to a set simulated actual formation temperature. Specifically, heat the core holder 16 to the temperature required for the experiment. For a coalbed methane reservoir, the experimental temperature should simulate the actual formation temperature. Usually, the formation temperature ranges from 40°C to 70°C. The specific temperature depends on the depth and geothermal gradient of the target reservoir (for example, assuming that the target reservoir is located at a depth of about 2000 meters and the geothermal gradient is about 25°C / km, then the experimental temperature should be set at about 50°C);

[0046] Step 5: Start the annular pressure pump 17 to adjust the confining pressure in the core holder 16 to achieve the set pressure condition matching the actual reservoir. It should be noted that the pressure of the coalbed methane reservoir is generally high, and the pressure value depends on the depth and geological conditions of the reservoir (for example, assuming that the average pressure of the target reservoir is 15 MPa). The annular pressure pump 17 is used for precise adjustment to ensure constant pressure and simulate the actual reservoir environment.

[0047] Step 6: Turn on the low-field nuclear magnetic resonance instrument 19 to scan and measure the core sample to obtain the T2 relaxation time distribution, and analyze the distribution inside the rock matrix pores in combination with the data. Specifically, the low-field nuclear magnetic resonance instrument 19 is specially used to evaluate the pore fluid characteristics in the rock sample and the pore structure of the coal shale. During the measurement, the Carr-Purcell-Meiboom-Gill (CPMG) sequence is used to obtain the T2 relaxation time distribution in the coal shale sample, and the distribution inside the rock matrix pores is analyzed in combination with this data;

[0048] Step 7: Analyze the chemical composition and substance concentration of the fracturing fluid by the first liquid chromatograph 12 to obtain the baseline chemical data of the fracturing fluid before injection. Specifically, before the formal experiment, the fracturing fluid is transferred to the first liquid chromatograph 12 for chemical composition and substance concentration analysis. This step is to obtain the baseline chemical data of the fracturing fluid before injection for comparative analysis of subsequent results. The first liquid chromatograph 12 is set to detect specific organic markers and possible pollutants (for example, using a UV detector to detect aromatic compounds, and maintaining the chromatographic column temperature at 30° C. to optimize the separation effect and improve reproducibility);

[0049] Step 8. Use the fracturing fluid delivery and injection system to maintain the set flow rate and pressure to inject into the core holder 16, and conduct a set period of coal rock core fracturing fluid imbibition experiment to obtain a saturated fracturing fluid coal rock core. Specifically, the fracturing fluid delivery and injection system sets the flow rate and pressure parameters of the fracturing fluid. To simulate the actual formation conditions, the experiment sets the injection flow rate of the fracturing fluid to 5mL / min and the pressure to 15MPa to ensure that the fracturing fluid is transported to the core under pressure. Conduct a 7-10 day coal rock core fracturing fluid imbibition experiment to obtain a saturated fracturing fluid coal rock core. Real-time monitoring of the flow rate and pressure data of the fracturing fluid, as well as the pressure and temperature in the core holder 16, ensure that these parameters meet the experimental set values, and record the experimental data for subsequent analysis;

[0050] Step nine, use a high-pressure gas drive system to inject high-pressure gas into the core holder 16 to displace the fracturing fluid in the core holder 16 until no liquid flows out of the outlet of the core holder 16, and collect and weigh it in a weighing container to obtain the weight of the fracturing fluid discharged during the experiment. During the gas drive process, the high-pressure gas will push the fracturing fluid in the core to move to the other end of the core holder 16, monitor the port where the liquid flows out, and once it is observed that no more liquid is produced, continue to deliver additional gas for a period of time (set to 1 hour) to ensure that the liquid in the core is removed as much as possible and to minimize the residual fracturing fluid. At the same time, after the gas drive is completed, use a precision weighing device 18 to measure the displacement of the fracturing fluid (wherein the precision of the precision weighing device 18 should be at least 0.01 grams to ensure the accuracy of the measurement result), calculate the weight increase measured by the precision weighing device 18, and calculate the total weight of the fracturing fluid discharged during the experiment;

[0051] At the same time, during the gas drive process, a low-field nuclear magnetic resonance instrument 19 was used to conduct a detailed analysis of the coal core after gas drive. The T2 relaxation time was measured at different gas drive times (2h, 4h, and 6h in this experiment) to evaluate the pore structure and residual fluid state in the core. The nuclear magnetic resonance analysis parameters such as the frequency were set to 2MHz, and the scanning time was set according to the sample size and the required resolution, usually 30 minutes;

[0052] Step 10: Perform secondary analysis on the removed fracturing fluid using the second liquid chromatograph 23. Specifically, use the second liquid chromatograph 23, set the temperature to 30°C, set the chromatographic conditions to a C18 column, use a gradient elution of water as the mobile phase, flow rate 1.0 mL / min, and detection wavelength 254 nm to analyze possible organic pollutants and residual chemical additives. Then compare with the first analysis result obtained in step 7, analyze the changes in chemical composition and concentration before and after passing through the core sample, and after analysis, transfer the collected fracturing fluid to the liquid recovery device 24 for further processing or disposal;

[0053] Step 11: Calculate the imbibition rate S of the fracturing fluid of the core sample using Formula 1, and calculate the retention rate R of the fracturing fluid under different gas drive time conditions using Formula 2, as follows:

[0054] Formula 1

[0055] Formula 2

[0056] Among them, V f is the total volume of fracturing fluid injected into the core (ml), A t is the total surface area of ​​the core (cm 2 ), V r is the volume of fracturing fluid discharged from the core.

[0057] As a preferred embodiment, the high-pressure gas drive system includes a high-pressure gas source 1 and a first stop valve 3, a filter 5, a pressure regulating valve 6 and an air intake valve 8 which are connected in series with the outlet of the high-pressure gas source 1 through a pipeline. A first pressure gauge 4 is provided on the pipe section between the first stop valve 3 and the filter 5, and a second pressure gauge 7 is provided on the pipe section between the pressure regulating valve 6 and the air intake valve 8.

[0058] In the above implementation scheme, the gas-driven liquid operation is performed on the cores with different imbibition times, and the gas-driven process of the coal shale fracturing fluid is realized, which includes the following steps:

[0059] S1: Open the first stop valve 3 to allow the gas in the high-pressure gas source 1 to flow into the filter 5, wherein the filter 5 is used to remove impurities in the gas to ensure that the gas entering the system is pure and avoid contamination of the experimental equipment and core samples;

[0060] S2: Regulate the pressure regulating valve 6 to set the gas pressure. To simulate the actual formation pressure, assume that the set pressure is 10 MPa. The first pressure gauge 4 and the second pressure gauge 7 cooperate to monitor the gas pressure in real time to ensure that it is within the set range.

[0061] S3: The regulated gas enters the core holder 16 through the inlet valve 8, and the gas-to-liquid process begins. During this process, the high-pressure gas will push the fracturing fluid in the core to the other end (outlet section) of the core holder 16. The outlet end is monitored. Once no more liquid is observed to be produced, the gas is continued to be transported for a period of time to ensure that the liquid in the core is removed as much as possible.

[0062] As a preferred embodiment, the fracturing fluid delivery and injection system includes a liquid container 2 and a second stop valve 10, a constant pressure and constant speed pump 11 and the first liquid chromatograph 12 which are connected in series with the outlet of the liquid container 2 through a pipeline. The second stop valve 10 and the liquid inlet valve 13 are respectively provided on the pipe section of the pipeline corresponding to the outlet of the liquid container 2 and between the first liquid chromatograph 12 and the core clamp 16.

[0063] In the above embodiment, the steps of injecting the fracturing fluid are as follows:

[0064] Open the second stop valve 10 and the liquid inlet valve 13, and start the constant pressure and constant speed pump 11 to pump the fracturing fluid to the core clamp 16. During this process, the constant pressure and constant speed pump 11 continues to maintain the set flow rate and pressure (5 mL / min, 15 MPa) to ensure that the fracturing fluid is transported to the core sample under pressure.

[0065] In this embodiment, one end inlet of the core clamp 16 is connected to a four-way valve, the high-pressure gas drive system and the fracturing fluid delivery and injection system are respectively connected to two interfaces of the four-way valve through pipelines, and the remaining interface of the four-way valve is connected to a third pressure gauge 14.

[0066] In this embodiment, the precision weighing device 18 comprises a precision balance, and a weighing container for receiving the fracturing fluid is installed on the precision balance.

[0067] In this embodiment, the heating device 15 is an electric heating tube disposed outside the core holder 16 .

[0068] Alternatively, the heating device 15 may be a heating chamber disposed outside the core holder 16 .

[0069] As a preferred embodiment, the system further comprises a computer 9 , which is connected to the first liquid chromatograph 12 , the second liquid chromatograph 23 and the heating device 15 .

[0070] In the above implementation scheme, the entire device is equipped with a computer 9, and the main first liquid chromatograph 12, the second liquid chromatograph 23 and the heating device 15 are connected to the computer to realize intelligent operation and data collection.

[0071] In this embodiment, the valves involved in the device are all electronic valves of corresponding models, and are all connected to the computer 9 or the configured control terminal to realize automatic control of the experimental process. The multi-stage pressure regulating valve in the device provides different levels of pressure regulation functions, and cooperates with the temperature controller and the ring pressure pump that accurately adjust and maintain, so as to simulate the temperature and pressure conditions of different formations. The device not only increases the application scope and flexibility of the experiment, but also ensures the precise control of temperature and pressure during the experiment, meeting the needs of complex and changeable experimental environments.

[0072] As a preferred embodiment, it also includes a gas recovery device 22, a three-way valve 20 is connected in series on the pipeline connecting the liquid outlet and the liquid recovery device 24, the remaining interface of the three-way valve 20 is connected to the gas recovery device 22 through a pipeline, and a gas flow meter 21 is provided on the pipeline.

[0073] In the above implementation scheme, after completing the gas delivery (gas drive process), the high-pressure gas source 1 and the related valves are closed, and the gas generated during the treatment process is guided to the gas recovery device 22 through a special pipeline to gradually reduce the pressure in the system and safely end the gas drive experiment.

[0074] In the description of the present invention, it is to be understood that the terms “center”, “longitudinal”, “lateral”, “length”, “width”, “thickness”, “up”, “down”, “front”, “back”, “left”, “right”, “vertical”, “horizontal”, “top”, “bottom”, “inside”, “outside”, “clockwise”, “counterclockwise”, “axial”, “radial”, “circumferential”, etc., indicating orientations or positional relationships based on the orientations or positional relationships shown in the accompanying drawings, are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the referred device or element must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be understood as limiting the present invention.

[0075] In addition, the terms "first" and "second" are used for descriptive purposes only and should not be understood as indicating or implying relative importance or implicitly indicating the number of the indicated technical features. Therefore, the features defined as "first" and "second" may explicitly or implicitly include at least one of the features. In the description of the present invention, the meaning of "plurality" is at least two, such as two, three, etc., unless otherwise clearly and specifically defined.

[0076] In the present invention, unless otherwise clearly specified and limited, the terms "installed", "connected", "connected", "fixed" and the like should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be a direct connection or an indirect connection through an intermediate medium, it can be the internal connection of two elements or the interaction relationship between two elements, unless otherwise clearly defined. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0077] In the present invention, unless otherwise clearly specified and limited, a first feature being "above" or "below" a second feature may mean that the first and second features are in direct contact, or the first and second features are in indirect contact through an intermediate medium. Moreover, a first feature being "above", "above" or "above" a second feature may mean that the first feature is directly above or obliquely above the second feature, or simply means that the first feature is higher in level than the second feature. A first feature being "below", "below" or "below" a second feature may mean that the first feature is directly below or obliquely below the second feature, or simply means that the first feature is lower in level than the second feature.

[0078] In the description of this specification, the description with reference to the terms "one embodiment", "some embodiments", "example", "specific example", or "some examples" etc. means that the specific features, structures, materials or characteristics described in conjunction with the embodiment or example are included in at least one embodiment or example of the present invention. In this specification, the schematic representations of the above terms do not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials or characteristics described may be combined in any one or more embodiments or examples in a suitable manner. In addition, those skilled in the art may combine and combine the different embodiments or examples described in this specification and the features of the different embodiments or examples, without contradiction.

[0079] Although the embodiments of the present invention have been shown and described above, it is to be understood that the above embodiments are exemplary and are not to be construed as limitations of the present invention. A person skilled in the art may change, modify, replace and vary the above embodiments within the scope of the present invention.

Claims

1. An in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid, characterized by: The invention comprises a high-pressure gas drive system, a core holder (16), a fracturing fluid delivery and injection system, a precision weighing device (18) and a liquid recovery device (24), wherein the high-pressure gas drive system and the fracturing fluid delivery and injection system are respectively connected to an inlet at one end of the core holder (16) through a pipeline, and a first liquid chromatograph (12) is connected in series to the pipeline connecting the fracturing fluid delivery and injection system and the core holder (16), and the outlet at the other end of the core holder (16) is connected to the outlet via a pipeline. A weighing container is placed on the precision weighing device (18), a liquid outlet is provided at the bottom of the weighing container, the liquid outlet is connected to the liquid recovery device (24) through a pipeline, and a second liquid chromatograph (23) is connected in series to the pipeline, the core holder (16) is provided with a heating device (15) for heating the inside thereof and a low-field nuclear magnetic resonance instrument (19) for scanning and analyzing the core sample inside thereof, and the inner cavity of the core holder (16) is connected to an annular pressure pump (17).

2. The in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 1, characterized in that: The high-pressure gas drive system comprises a high-pressure gas source (1) and a first stop valve (3), a filter (5), a pressure regulating valve (6) and an air intake valve (8) which are connected in series with the outlet of the high-pressure gas source (1) via a pipeline, a first pressure gauge (4) being provided on the pipe section between the first stop valve (3) and the filter (5), and a second pressure gauge (7) being provided on the pipe section between the pressure regulating valve (6) and the air intake valve (8).

3. The in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 1, characterized in that: The fracturing fluid delivery and injection system comprises a liquid container (2) and a second stop valve (10), a constant pressure and constant speed pump (11) and the first liquid chromatograph (12) which are connected in series with the outlet of the liquid container (2) via a pipeline. The second stop valve (10) and the liquid inlet valve (13) are respectively provided on the pipe section of the pipeline corresponding to the outlet of the liquid container (2) and between the first liquid chromatograph (12) and the core holder (16).

4. The in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 1, characterized in that: The inlet at one end of the core holder (16) is connected to a four-way valve, the high-pressure gas drive system and the fracturing fluid delivery and injection system are respectively connected to two interfaces of the four-way valve through pipelines, and the remaining interface of the four-way valve is connected to a third pressure gauge (14).

5. The in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 1, characterized in that: The precision weighing device (18) comprises a precision balance.

6. The in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 1, characterized in that: The heating device (15) is an electric heating tube arranged outside the core holder (16).

7. The in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 1, characterized in that: The heating device (15) is a heating chamber arranged outside the core holder (16).

8. An in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to claim 6 or 7, characterized in that: The invention also comprises a computer (9), wherein the computer (9) is connected to the first liquid chromatograph (12), the second liquid chromatograph (23) and the heating device (15).

9. An in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to any one of claims 1 to 7, characterized in that: It also includes a gas recovery device (22), a three-way valve (20) is connected in series on the pipeline connecting the liquid outlet and the liquid recovery device (24), the remaining interface of the three-way valve (20) is connected to the gas recovery device (22) through a pipeline, and a gas flow meter (21) is provided on the pipeline.

10. An in-situ analysis method for the imbibition and retention characteristics of coal shale fracturing fluid, implemented using the in-situ analysis device for the imbibition and retention characteristics of coal shale fracturing fluid according to any one of claims 1 to 9, characterized in that: The following steps are involved: Step 1: preparing a core sample of set size and porosity; Step 2: drying the core sample and placing it in a core holder (16); Step 3: preparing the fracturing fluid and loading it into the fracturing fluid delivery and injection system; Step 4: Turn on the heating device (15) to heat the core sample in the core holder (16) to a set simulated actual formation temperature; Step 5: Start the annular pressure pump (17) to adjust the confining pressure in the core holder (16) to achieve a set pressure condition matching the actual reservoir; Step 6: Turn on the low-field nuclear magnetic resonance instrument (19) to scan and measure the core sample to obtain the T2 relaxation time distribution, and analyze the distribution of the pores inside the rock matrix based on the data; Step 7: Analyze the chemical composition and substance concentration of the fracturing fluid by a first liquid chromatograph (12) to obtain baseline chemical data of the fracturing fluid before injection; Step 8: Using the fracturing fluid delivery and injection system to maintain a set flow rate and pressure to inject into the core holder (16), and perform a set period of fracturing fluid imbibition experiment on the coal rock core to obtain a saturated fracturing fluid coal rock core; Step nine, using a high-pressure gas drive system to inject high-pressure gas into the core holder (16) to displace the fracturing fluid in the core holder (16) until no liquid flows out of the outlet of the core holder (16), and collecting and weighing the liquid in a weighing container to obtain the weight of the fracturing fluid discharged during the experiment; at the same time, during the injection of high-pressure gas, using a low-field nuclear magnetic resonance instrument (19) to measure the T2 relaxation time at different gas drive times to evaluate the pore structure and residual fluid state in the core; Step 10: Perform secondary analysis on the removed fracturing fluid using a second liquid chromatograph (23), and then compare the analysis result with the first analysis result obtained in step 7 to analyze the changes in chemical composition and concentration before and after passing through the core sample. After the analysis, the collected fracturing fluid is stored in a liquid recovery device (24); Step 11: Calculate the imbibition rate S of the fracturing fluid of the core sample using Formula 1, and calculate the retention rate R of the fracturing fluid under different gas drive time conditions using Formula 2, as follows: Formula 1 Formula 2 Among them, V f is the total volume of fracturing fluid injected into the core, ml; V r is the volume of fracturing fluid discharged from the core.

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