Directional long hole multi-stage hydraulic fracturing and high pressure nitrogen displacement enhanced extraction method

Abstract

The application discloses a directional long drilling multistage hydraulic fracturing and high-pressure nitrogen displacement enhanced extraction method, and belongs to the technical field of coal mine gas extraction. The method constructs a directional long drilling hole in a target coal seam, and arranges fracturing branch holes and gas injection branch holes according to the drilling hole track and coal seam occurrence parameters; after the holes are sealed by using double packers, segmented reverse hydraulic fracturing is carried out in the fracturing branch holes; after a predetermined water injection amount is reached, high-pressure nitrogen is injected through the gas injection branch holes, the fracturing fluid is displaced by using a driving effect, and the coal seam is fractured again by using pressure pulses; after the injection is completed, the gas injection branch holes are switched to an extraction state, mixed fluid is extracted under negative pressure, and the coal seam is fractured for a third time by alternately carrying out pressure extraction and pumping, so that the enhanced extraction effect is maintained. The method can effectively displace the fracturing fluid, realize multiple fracturing to improve the permeability of the coal seam, and maintain a long-time and high-efficiency gas extraction state.

Description

Technical Field

[0001] This invention relates to the field of coal mine gas extraction technology, specifically a method for directional long borehole multi-stage hydraulic fracturing and high-pressure nitrogen displacement to enhance gas extraction. Background Technology

[0002] Coal seam gas drainage commonly employs a combination of directional long boreholes and hydraulic fracturing to improve coal seam permeability. Hydraulic fracturing initiates fracturing with high-pressure fluid and expands the original fractures in the coal seam, forming an artificial fracture network. After fracturing, due to fracture closure and obstructed drainage channels, a large amount of fracturing fluid remains trapped within the fracture space, causing a severe water-locking effect, significantly reducing gas seepage channels, and weakening the permeability-enhancing effect. The fracture network formed by a single hydraulic fracturing operation gradually closes under the pressure of geostress during long-term drainage, and the permeability enhancement capacity rapidly declines over time, leading to a continuous decrease in gas drainage concentration and production, failing to meet the requirements for efficient and continuous drainage. Some processes implement gas injection measures after fracturing, injecting carbon dioxide or nitrogen into the coal seam to displace gas. However, the injection objective is mainly focused on displacement and desorption, with insufficient attention paid to fracturing fluid displacement and re-fracture of the coal seam, leaving the liquid phase retention problem unresolved. Gas injection under constant pressure lacks pressure pulse action, making it difficult to cause fatigue damage to the coal seam and further expand fractures. Incomplete fracturing fluid removal, limited methods for improving coal seam permeability, and the inability to maintain permeability enhancement effects in the long term constitute prominent challenges that restrict the effectiveness of gas extraction. Summary of the Invention

[0003] This invention provides a method for multi-stage hydraulic fracturing with high-pressure nitrogen displacement and enhanced gas extraction in directional long boreholes. The purpose is to solve the problems of fracturing fluid retention and blockage of fractures after hydraulic fracturing and the short duration of the effect of a single permeability enhancement method. At the same time, it achieves efficient displacement of fracturing fluid, multiple fracturing of coal seams, and long-term efficient gas extraction.

[0004] To achieve the above objectives, the present invention provides the following technical solution: The present invention provides a method for multi-stage hydraulic fracturing and high-pressure nitrogen displacement to enhance the extraction efficiency of coalbed methane by organically integrating hydraulic fracturing and gas displacement combined extraction operations, thereby achieving multi-stage permeability enhancement treatment of the target coal seam from primary fracturing, secondary displacement fracturing to tertiary cyclic disturbance fracturing, thus significantly improving the extraction efficiency of coalbed methane.

[0005] To achieve the above objectives, the method of the present invention includes: drilling directional long boreholes in the target coal seam; arranging fracturing branch holes and gas injection branch holes according to the borehole trajectory of the directional long boreholes and the occurrence parameters of the target coal seam; sealing the fracturing branch holes and the gas injection branch holes respectively using double packers; performing segmented reverse hydraulic fracturing operations in the fracturing branch holes; and using high-pressure water injection pumps to initiate and expand the original fracture network of the target coal seam segment by segment, forming an initial fracture communication system with the directional long boreholes as the skeleton and each branch hole as the radiating surface.

[0006] After the segmented reverse hydraulic fracturing operation reaches the predetermined water injection volume, the hydraulic fracturing operation is stopped. The gas injection branch hole is connected to the high-pressure nitrogen injection equipment, and high-pressure nitrogen is injected into the target coal seam through the gas injection branch hole. The driving effect of the high-pressure nitrogen is used to backflow the fracturing fluid in the fracturing branch hole, and the pressure pulse of the high-pressure nitrogen is used to perform secondary fracturing on the target coal seam, further connecting the isolated micro fractures in the coal seam.

[0007] After the high-pressure nitrogen injection reaches the predetermined injection volume, the high-pressure nitrogen injection is stopped, and the injection branch hole is switched to the extraction state. The mixed fluid that has accumulated in the target coal seam under the drive of high-pressure nitrogen is discharged through negative pressure extraction. By utilizing the alternating operation mode of pressure extraction formed by fracturing injection, high-pressure nitrogen drive, and negative pressure extraction, periodic pressure disturbances are applied to the target coal seam to achieve three-stage fracturing and continuously maintain the unobstructed coal seam fracture network, thereby improving the gas desorption and migration effect.

[0008] As a preferred embodiment of the present invention, the process of arranging fracturing branch holes and gas injection branch holes according to the drilling trajectory of the directional long borehole and the occurrence parameters of the target coal seam includes: obtaining the drilling trajectory parameters of the directional long borehole, the drilling trajectory parameters including the drilling azimuth angle, drilling dip angle and drilling depth; determining the main fracture development direction and coal seam thickness distribution of the target coal seam according to the occurrence parameters of the target coal seam, the occurrence parameters including the coal seam thickness, coal seam dip angle, fracture density and fracture orientation; based on the drilling trajectory parameters and the occurrence parameters, setting the fracturing branch holes and the gas injection branch holes in a direction forming a predetermined angle with the main fracture development direction, so that the fracturing branch holes and the gas injection branch holes are alternately arranged along the axial direction of the directional long borehole, and the final positions of the fracturing branch holes and the gas injection branch holes are distributed at different thickness layers of the target coal seam. This allows the fracturing action zone and the gas injection displacement zone to overlap spatially, avoiding interference between the fracturing fluid flow direction and the nitrogen displacement direction, and enabling three-dimensional modification of the entire coal seam thickness.

[0009] Preferably, the process of performing segmented reverse hydraulic fracturing operations within the fracturing branch hole includes: obtaining the drilling depth of the fracturing branch hole and the fracturing initiation pressure threshold of the target coal seam; dividing the fracturing branch hole into multiple fracturing segments according to the drilling depth, with each fracturing segment corresponding to a fracturing depth range; lowering the double packer to the first fracturing segment furthest from the borehole opening; starting the high-pressure water injection pump to inject fracturing fluid into the first fracturing segment; monitoring the injection pressure of the first fracturing segment in real time until the injection pressure reaches the fracturing initiation pressure threshold and fracturing continues to propagate, at which point injection is stopped; after completing the fracturing operation of the first fracturing segment, adjusting the double packer to the next adjacent fracturing segment via the drill pipe; repeating the operation of injecting fracturing fluid and monitoring the injection pressure until the fracturing operation of all fracturing segments is completed, forming a reverse fracturing sequence from the bottom of the borehole to the borehole opening. This backward fracturing method allows the operation of the subsequent fracturing stage to utilize the fracture field already formed in the preceding fracturing stage for pressure transmission, reducing the difficulty of initiating fracturing in deep coal seams and increasing the fracturing radius.

[0010] Preferably, after completing the fracturing operation of the first fracturing section, the process of adjusting the double packer to the adjacent next fracturing section via the drill pipe includes: recording the pump stop pressure value and the cumulative injection volume of fracturing fluid when the first fracturing section completes fracturing initiation and propagation; calculating the fracture propagation radius corresponding to the first fracturing section based on the pump stop pressure value and the cumulative injection volume of fracturing fluid; determining the moving distance of the double packer along the fracturing branch hole based on the fracture propagation radius and the fracturing initiation pressure correction value of the next fracturing section, wherein the fracturing initiation pressure correction value is obtained based on the measured value of coal seam in-situ stress in the depth range where the next fracturing section is located; raising the drill pipe according to the moving distance, thereby moving the double packer to the next fracturing section, and sealing the upper and lower packers of the double packer at the upper and lower boundary positions of the next fracturing section respectively, forming a closed fracturing space of the next fracturing section, thereby precisely controlling the sealing position of the fracturing section and ensuring effective connection of the fracture network between adjacent fracturing sections.

[0011] Preferably, the fracturing depth ranges between two adjacent fracturing sections partially overlap, and the overlap length is determined according to the fracture connectivity radius of the target coal seam, in order to ensure the continuity and connection of the fracture network between adjacent fracturing sections and avoid the formation of fracturing blank zones.

[0012] As a preferred embodiment of the present invention, the process of injecting high-pressure nitrogen into the target coal seam through the injection branch hole includes: obtaining the rated output pressure and rated flow rate of the high-pressure nitrogen injection equipment; setting the initial injection pressure and initial injection flow rate based on the rated output pressure and rated flow rate; dynamically adjusting the initial injection pressure and initial injection flow rate based on the liquid level of the residual fracturing fluid in the fracturing branch hole and the permeability of the target coal seam to generate a dynamic injection parameter sequence; injecting high-pressure nitrogen into the target coal seam in segments through the injection branch hole according to the dynamic injection parameter sequence, monitoring the injection pressure change rate during each segment, and adjusting the injection duration of the current segment according to the injection pressure change rate until a predetermined total injection volume is reached, thereby maximizing the nitrogen sweep volume while avoiding coal seam breakdown by high-pressure gas.

[0013] Preferably, the process of dynamically adjusting the injection parameters based on the residual fracturing fluid level in the fracturing branch hole and the permeability of the target coal seam includes: acquiring fluid level monitoring data in the fracturing branch hole; calculating the fluid level drop rate of the residual fracturing fluid based on the fluid level monitoring data, wherein the fluid level drop rate reflects the rate at which the residual fracturing fluid is lost into the fractures of the target coal seam; calculating the minimum driving pressure value required for high-pressure nitrogen to displace the residual fracturing fluid based on the fluid level drop rate and the permeability of the target coal seam; comparing the initial injection pressure value with the minimum driving pressure value; if the initial injection pressure value is less than the minimum driving pressure value, increasing the initial injection pressure value to above the minimum driving pressure value; and adjusting the initial injection flow rate value accordingly based on the real-time changes in the fluid level drop rate to ensure that the high-pressure nitrogen propels the fracturing fluid with appropriate energy and displacement, effectively and smoothly pushing the fracturing fluid front away from the wellbore area.

[0014] As a preferred technical solution of the present invention, the process of switching the gas injection branch hole to the extraction state and discharging the mixed fluid in the target coal seam by negative pressure extraction includes: closing the output valve of the high-pressure nitrogen injection equipment; connecting the orifice of the gas injection branch hole to the gas inlet of the extraction pipeline, wherein the extraction pipeline is equipped with a vacuum pump and a gas-liquid separator; starting the vacuum pump to apply negative pressure extraction force to the gas injection branch hole, and extracting the mixed fluid in the target coal seam through the gas injection branch hole, wherein the mixed fluid contains high-pressure nitrogen, residual fracturing fluid and coal seam desorption gas; introducing the mixed fluid into the gas-liquid separator for gas-liquid separation treatment, collecting the separated liquid fracturing fluid in a storage tank, and transporting the separated gaseous mixed gas to a gas collection pipeline, thereby realizing the simultaneous extraction and separation of injected gas and desorption gas from the surface.

[0015] Preferably, the process of performing three fracturing operations on the target coal seam through alternating pressure and extraction to maintain a long-term, high-efficiency extraction state includes: recording the extraction negative pressure value and extraction gas volume change curve of the gas injection branch hole in the extraction state; determining whether the gas desorption rate of the target coal seam has reached the attenuation threshold based on the extraction gas volume change curve; when the gas desorption rate reaches the attenuation threshold, shutting off the vacuum pump and reconnecting the gas injection branch hole to the high-pressure nitrogen injection equipment, injecting high-pressure nitrogen into the target coal seam again according to the secondary injection pressure value to form periodic pressure fluctuations for three fracturing operations on the target coal seam; after completing the three fracturing operations, switching the gas injection branch hole back to the extraction state, and performing multiple alternating pressure and extraction operations in an alternating cycle. The injection pressure value and extraction negative pressure value of each alternating cycle are dynamically adjusted according to the gas extraction concentration of the previous alternating cycle, so that the pressure disturbance amplitude matches the current desorption capacity of the coal seam.

[0016] Preferably, in multiple alternating cycles, the secondary injection pressure value decreases successively, while the extraction negative pressure value increases successively, so as to form an asymmetric pressure fluctuation load to cumulatively damage and fracture the target coal seam, avoid excessive fragmentation of the coal body structure caused by repeated high-pressure injection, and continuously enhance the desorption and diffusion dynamics of gas in the low-pressure area.

[0017] The technical effects and advantages provided by the present invention in the above technical solution are as follows:

[0018] In segmented reverse hydraulic fracturing, sequential fracturing from the bottom to the orifice is created within the fracturing branch holes. Once the predetermined water injection volume is reached, hydraulic fracturing operations cease, and high-pressure nitrogen is injected into the target coal seam through the gas injection branch holes. The high-pressure nitrogen creates a driving effect within the coal seam fracture network, propelling residual fracturing fluid along the fractures towards the fracturing branch holes and extraction channels, relieving the blockage of gas flow channels by liquid locks, and restoring and improving fracture conductivity. Simultaneously, the pressure pulses of the high-pressure nitrogen generate periodically fluctuating pore pressure within the coal mass, applying alternating tensile stress to the fracture tips and coal matrix. This causes repeated opening and closing of primary fractures and those formed by hydraulic fracturing, inducing fatigue damage and localized fracturing in the coal mass, generating new microfractures, and driving existing fractures to extend and connect further, completing the secondary fracturing of the coal seam. The coal seam permeability significantly increases under the combined effects of liquid lock removal and fatigue fracturing. After hydraulic fracturing and nitrogen displacement are completed, the injection branch holes are switched to extraction mode to drain the mixed fluid in the coal seam using negative pressure extraction. When the coal seam gas desorption rate decreases, extraction is shut off and high-pressure nitrogen is injected again, forming an alternating pressure-extraction operation. The periodic "pressurization-depressurization" loading method applies repeated asymmetric pressure fluctuations to the coal and rock mass, creating a cumulative damage effect. This causes the fractures to continuously open, expand, and extend during the alternating process, achieving tertiary fracturing and preventing the fractures from closing under geostress. The pressure fluctuations simultaneously disturb the gas adsorption balance in the matrix, promoting the desorption of adsorbed gas and its diffusion into the fractures, maintaining high gas desorption activity. Through multiple alternating pressure-extraction cycles, with the injection pressure decreasing successively and the extraction negative pressure increasing successively, a gradual fatigue fracturing and displacement extraction synergistic effect is constructed, continuously enhancing and maintaining the coal seam's permeability and production increase effect. Attached Figure Description

[0019] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments recorded in this invention. For those skilled in the art, other drawings can be obtained based on these drawings.

[0020] Figure 1 This is a flowchart of a method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping.

[0021] Figure 2 This is a schematic diagram of the arrangement of fracturing branch holes and gas injection branch holes;

[0022] Figure 3 This is a flowchart of the reverse segmented fracturing construction process using branch holes;

[0023] Figure 4 This is a flowchart of the method for determining the moving distance and setting the double packer;

[0024] Figure 5This is a flowchart of the high-pressure nitrogen displacement of residual fracturing fluid staged injection control method. Detailed Implementation

[0025] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, 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, 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.

[0026] See Figure 1 This invention provides a method for multi-stage hydraulic fracturing with directional long boreholes and high-pressure nitrogen displacement pumping. The method includes: drilling directional long boreholes in a target coal seam; arranging fracturing branch holes and gas injection branch holes according to the borehole trajectory and the occurrence parameters of the target coal seam; sealing the fracturing branch holes and gas injection branch holes with double packers; performing segmented reverse hydraulic fracturing operations within the fracturing branch holes; and using a high-pressure water injection pump to initiate and expand the original fracture network of the target coal seam segment by segment. After the segmented reverse hydraulic fracturing operation reaches a predetermined water injection volume, the hydraulic fracturing operation is stopped. The gas injection branch holes are then connected to a high-pressure nitrogen injection device, and high-pressure nitrogen is injected into the target coal seam through the gas injection branch holes. The driving effect of the high-pressure nitrogen is used to backflow the fracturing fluid within the fracturing branch holes, and the pressure pulse of the high-pressure nitrogen is used to induce secondary fracturing in the target coal seam. After the high-pressure nitrogen injection reaches the predetermined injection volume, the high-pressure nitrogen injection is stopped, and the injection branch hole is switched to the extraction state. The mixed fluid in the target coal seam is discharged in the negative pressure extraction mode. The target coal seam is fracturing three times through alternating pressure and extraction operations, and the extraction effect is maintained.

[0027] Example 1: In specific implementation, please refer to Figure 2 The drilling trajectory parameters for directional long boreholes are obtained through a measurement-while-drilling (MWD) system. During drilling, the MWD system collects and records the borehole azimuth, inclination, and depth in real time, with a data collection frequency set to one set per meter of drilling. The borehole azimuth is measured clockwise from true north to the direction projected onto the horizontal plane, in degrees. The borehole inclination is measured in degrees, with positive values ​​for upward inclination and negative values ​​for downward inclination. The borehole depth is measured in meters, from the borehole opening along the borehole axis to the measurement point. All measurement data are sorted by depth to form a borehole trajectory parameter curve, which contains the coordinate sequence of the borehole in three-dimensional space.

[0028] The occurrence parameters of the target coal seam were obtained by combining field geological exploration data with underground measurements. Coal seam thickness was obtained by interpolating the thickness revealed at coal-bearing points in underground boreholes with seismic inversion data. Coal seam dip angle was calculated by the ratio of the elevation difference to the horizontal distance of the coal seam floor contour lines. Fracture density was obtained by statistically analyzing the number of fractures per unit area using underground coal wall fracture sketches. Fracture orientation was determined by measuring the fracture surface attitude and taking the azimuth of the orientation line. Coal seam thickness distribution was mapped using Kriging interpolation to generate coal seam thickness contour maps. The main fracture development direction was statistically analyzed using a rose diagram, classifying fracture orientation data at each measuring point into sector intervals and selecting the orientation interval with the highest fracture frequency as the main fracture development direction. Coal seam thickness distribution data was stored in a three-dimensional grid, with the coal seam thickness at each grid node representing the true thickness of the coal seam at the corresponding coordinates.

[0029] In the step of setting up fracturing branch holes and gas injection branch holes at a predetermined angle to the main fracture development direction based on borehole trajectory parameters and occurrence parameters, the predetermined angle is determined as follows: the main fracture development direction vector is projected onto the horizontal plane to obtain the horizontal direction line of the main fracture; this direction line is then rotated by a predetermined angle to obtain the horizontal azimuth line of the branch holes. The predetermined angle is set according to the relative relationship between the horizontal maximum principal stress direction of the target coal seam and the main fracture development direction, so that the extension direction of the fracturing branch holes and gas injection branch holes can promote the expansion of fracturing fluid and high-pressure nitrogen along the main fracture and connect a larger fracture network. When the angle between the main fracture development direction and the horizontal maximum principal stress direction is less than or equal to 15 degrees, the predetermined angle is 70 to 80 degrees; when the angle between the main fracture development direction and the horizontal maximum principal stress direction is greater than 15 degrees and less than or equal to 45 degrees, the predetermined angle is 50 to 60 degrees; when the angle between the main fracture development direction and the horizontal maximum principal stress direction is greater than 45 degrees, the predetermined angle is 30 to 40 degrees.

[0030] When setting the spatial positions of fracturing and gas injection branch holes, the axial direction of the directional long borehole is used as a baseline. The opening positions of fracturing and gas injection branch holes are alternately arranged at equal intervals along this baseline. The spacing between adjacent fracturing and gas injection branch holes is determined by the fracture connectivity radius of the target coal seam. This radius is obtained through numerical simulation of fracturing and is 60% of the fracture expansion radius under a certain fracturing scale and fracturing fluid injection volume. Each branch hole is drilled from its opening position along a predetermined angle. During drilling, the borehole inclination angle is adjusted in real time based on the coal seam thickness distribution grid data, ensuring that the final hole position of the fracturing branch hole is located at two-thirds to three-quarters of the depth in the coal seam thickness direction, and the final hole position of the gas injection branch hole is located at one-quarter to one-third of the depth in the coal seam thickness direction, achieving a staggered distribution of the final hole positions in the coal seam thickness direction. The borehole trajectory is adjusted by controlling the angle of the guide drill bit's bend joint and the tool face angle to ensure a smooth branch hole trajectory and that the final hole point falls within the target stratum range. The lengths of both the fracturing branch holes and the gas injection branch holes shall not exceed the drillable length of the target coal seam in the predetermined included angle direction, so as to avoid penetrating the top and bottom plates of the coal seam.

[0031] After completing the above arrangement, mark the orifice of each fracturing branch hole and gas injection branch hole and install the orifice device. Record the spatial coordinates, hole depth and final hole layer information of each branch hole into the downhole drilling construction database to form the layout diagram of the fracturing branch holes and gas injection branch holes. This layout diagram serves as the basis for subsequent double packer installation and fracturing operations.

[0032] Example 2: In specific implementation, please refer to Figure 3 The drilling depth of the fracturing branch hole was obtained by cumulative calculation of the drill string length combined with remeasurement using a laser rangefinder. The cumulative calculation of the drill string length recorded the total length of all drill rods and drill string assemblies during the drilling process. After the fracturing branch hole was completed, the laser rangefinder measured the distance to the non-liquid section in the hole. The difference between the two measurements was corrected for temperature compensation to obtain the actual drilling depth of the fracturing branch hole from the hole opening to the bottom of the hole.

[0033] The initiation pressure threshold of the target coal seam is determined by combining small-scale fracturing tests with in-situ stress back-calculation. After the fracturing branch hole is constructed, the bottom of the branch hole is selected as the test point. A single packer or a straddle packer is installed to isolate an open hole section with a length of 1.5 to 2 meters. Clean water is injected into this open hole section at a constant injection rate, and the injection pressure change curve over time is continuously recorded. When the injection pressure reaches its peak and then experiences a significant pressure drop, this peak pressure is recorded as the initiation pressure of the target coal seam. The initiation pressure of the open hole is then corrected for surrounding rock stress to obtain the initiation pressure threshold of the target coal seam. The calculation method for surrounding rock stress correction is as follows: the initiation pressure threshold is equal to the initiation pressure of the open hole minus the product of the borehole surrounding rock stress concentration factor and the vertical stress, plus the pore pressure of the target coal seam. Among them, the borehole surrounding rock stress concentration factor is taken as 1 to 1.3, the vertical stress is calculated from the burial depth of the target coal seam and the average unit weight of the overlying strata, and the pore pressure is determined based on the coal seam gas pressure and hydrostatic pressure.

[0034] In the process of dividing a fracturing branch hole into multiple fracturing segments based on the drilling depth, a reference length for each fracturing segment is determined. The reference length for a single fracturing segment is determined based on the rated injection capacity of the high-pressure water injection pump and the average diameter of the fracturing branch hole, ensuring that the fluid residence time within a single fracturing segment is sufficient to form a stable initiation pressure during fracturing fluid injection. The reference length ranges from eight to fifteen meters. The initial segment number is obtained by dividing the drilling depth by the reference length, and then rounded up to the nearest integer. These segments are numbered sequentially from the bottom of the hole towards the orifice as the first fracturing segment, the second fracturing segment, and so on up to the Nth fracturing segment. Each fracturing segment corresponds to a fracturing depth range. The starting point of the first fracturing segment is the bottom of the borehole, and the ending point of the first fracturing segment is the reference length moved from the bottom of the borehole towards the borehole opening plus half of the overlap length. The starting point of the second fracturing segment is the end point of the first fracturing segment minus the overlap length, and the ending point of the second fracturing segment is the reference length moved from the starting point of the second fracturing segment towards the borehole opening plus the overlap length, and so on. The ending point of the last fracturing segment is the borehole opening position or a protection segment that is one meter inward from the borehole opening.

[0035] The fracturing depth ranges between two adjacent fracturing sections partially overlap, and the overlap length is determined based on the fracture connectivity radius of the target coal seam. The fracture connectivity radius is calculated using fracturing numerical simulation software, taking into account the elastic modulus, Poisson's ratio, tensile strength, and fracturing initiation pressure threshold of the target coal seam. Specifically, the fracturing initiation pressure threshold is used as the borehole wall fracturing load input to simulate the fracture propagation process within the target coal seam, and the maximum radius of the stress disturbance region around the fracture tip is extracted as the fracture connectivity radius. The overlap length is calculated using the following formula:

[0036]

[0037] in, This indicates the overlap length between two adjacent fracturing sections, in meters. The radius of the fracture connectivity in the target coal seam is expressed in meters and is obtained from the above-mentioned hydraulic fracturing numerical simulation. The value ranges from 0.5 meters to 4 meters. This is the overlap coefficient, ranging from 0.2 to 0.5, with the specific value determined based on the fracture density of the target coal seam: when the fracture density is greater than ten fractures per meter, Take 0.2; when the fracture density is between five and ten fractures per meter, Take 0.35; when the crack density is less than five cracks per meter, The overlap coefficient is set to 0.5. The value of the overlap coefficient is based on the fact that the greater the fracture density, the better the fracture connectivity; a smaller overlap is sufficient to ensure the continuity of the fracture network. Conversely, a larger overlap is needed to compensate for the connectivity uncertainty caused by fracture sparsity. Overlap length. The minimum value is set to 0.3 meters to ensure that the packer setting section does not fall into the decompression influence zone of the previous fracturing section.

[0038] The dual packers are lowered to the first fracturing section furthest from the wellhead, designated as the first fracturing section. The dual packers consist of an upper packer and a lower packer connected by a central tube with fracturing fluid injection holes. The packers are hydraulically set, by pressurizing the drill pipe to expand the packer sleeve and allow it to adhere to the wall of the fracturing branch hole. During lowering, based on the drill pipe depth counter and the packer's magnetic positioning signal, the lower packer is positioned at the starting point of the first fracturing section (0.3 meters above the bottom of the fracturing branch hole), and the upper packer is positioned at the ending point of the first fracturing section (the upper boundary of the overlap length calculated). After both packers are set, a closed fracturing space is formed in the first fracturing section, with an axial length equal to the reference length plus half the overlap length.

[0039] The high-pressure water injection pump is started to inject fracturing fluid into the first fracturing stage. The fracturing fluid used is either clean water or activated water, with a drag-reducing agent added to lower pipeline friction. The high-pressure water injection pump is set to an initial injection rate of 0.5 cubic meters per minute. The injection pressure of the first fracturing stage is monitored in real time, collected by a pressure sensor installed at the center pipe of the double packer, at a frequency of once per second. When the injection pressure gradually rises and reaches the fracturing initiation pressure threshold, the wellhead pressure gauge shows an inflection point or a slight drop, indicating that fracturing has occurred in the rock of the fracturing branch hole wall. At this point, the injection rate is maintained and fracturing fluid injection continues, monitoring the stability of the injection pressure. When the injection pressure drops below 90% of the fracturing initiation pressure threshold and remains stable for more than three minutes, it is determined that the primary fracture network of the first fracturing stage has been sufficiently initiated and expanded. The high-pressure water injection pump is then stopped, the wellhead valve is closed, and the fracturing operation of the first fracturing stage is completed.

[0040] After completing the fracturing operation of the first fracturing section, the dual packers are adjusted via the drill pipe to the adjacent next fracturing section. The next fracturing section is the second fracturing section. The upper and lower packers of the dual packers are released, and the drill pipe is slowly raised by the drilling rig. The raising distance is determined by the overlap length and the reference length used when dividing the fracturing section. After raising, the lower packer reaches the starting point of the second fracturing section, and the upper packer reaches the ending point. The raising distance is calculated as the reference length minus the overlap length. During the raising process, the accurate setting position is ensured through dual verification using a drill pipe raising stroke recorder and a depth counter. After the dual packers reach the predetermined position in the second fracturing section, they are re-set, forming a closed fracturing space for the second fracturing section. Subsequently, the injection of fracturing fluid into the second fracturing section is repeated, with real-time monitoring of the injection pressure until the injection pressure reaches the fracturing initiation pressure threshold and fracturing continues to propagate, at which point the injection is stopped. Following the above method, fracturing operations were sequentially completed from the third fracturing stage to the Nth fracturing stage, forming a reverse fracturing sequence from the bottom of the borehole to the borehole opening. The injection pressure curve, cumulative injection volume, and pump shutdown pressure value were independently recorded for each fracturing stage, serving as the basis for subsequent analysis of fracture propagation.

[0041] Example 3: In specific implementation, please refer to Figure 4 The pump shutdown pressure value at the completion of the first fracturing stage is recorded as follows: After the high-pressure water injection pump stops running and the wellhead valve is closed, the pressure sensor installed at the center pipe of the double packer continues to collect pressure data at a frequency of once per second for 30 seconds. The arithmetic mean of the pressure readings within 30 seconds is taken as the pump shutdown pressure value. The pressure sensor is calibrated on a standard pressure calibration bench before each fracturing operation, with a calibration range covering 0 MPa to 40 MPa and an accuracy class of 0.2. The cumulative injection volume of fracturing fluid is measured by an electromagnetic flowmeter at the outlet of the high-pressure water injection pump. The electromagnetic flowmeter is reset to zero before the start of the first fracturing stage operation. During the operation, the product of the instantaneous flow rate and the sampling time interval is accumulated in real time. The cumulative volume displayed by the electromagnetic flowmeter at the end of the operation is the cumulative injection volume of fracturing fluid in the first fracturing stage, in cubic meters.

[0042] The process of calculating the fracture propagation radius of the first fracturing stage based on the pump shutdown pressure and the cumulative fracturing fluid injection volume employs a fracture propagation inversion model based on the mass conservation of fracturing fluid. This inversion model uses the net pressure within the fracture at the pump shutdown moment and the fracturing fluid loss volume as constraints, and obtains the fracture propagation radius through iterative solutions. The fracturing fluid mass conservation equation for the first fracturing stage is established: the cumulative fracturing fluid injection volume equals the sum of the fracture volume and the fracturing fluid loss volume. The fracture volume is expressed through a fracture geometry model, which considers the fracture as an elliptical fracture propagating symmetrically on both sides of the fracturing branch hole, with the fracture width radially conforming to an elliptical distribution, and the fracture length direction being the direction of the fracture propagation radius. The fracturing fluid loss volume is calculated using the Caterpillar loss model; the loss rate is inversely proportional to the fracturing fluid loss coefficient and the square root of the fracture wall exposure time.

[0043] The specific formula for calculating the crack propagation radius is as follows:

[0044]

[0045] in, This represents the fracture propagation radius corresponding to the first fracturing stage, in meters. The elastic modulus of the target coal seam is expressed in gigapascals (GPa). It is obtained through uniaxial compression tests on coal samples from underground mines. The tests are conducted in accordance with the standard "Methods for Determining Physical and Mechanical Properties of Coal and Rock". The elastic modulus is taken as the slope of the elastic segment of the stress-strain curve. This indicates the cumulative amount of fracturing fluid injected in the first fracturing stage, in cubic meters, and is read directly from the electromagnetic flowmeter. This represents the true thickness of the coal seam in the first fracturing section, in meters. The coal seam thickness value corresponding to the midpoint coordinates of the first fracturing section is extracted from the coal seam thickness distribution grid data. This represents the net pressure within the fracture of the first fracturing stage, in megapascals (MPA). It is obtained by subtracting the closure stress of the target coal seam from the pump shutdown pressure. The closure stress is taken as the minimum horizontal principal stress of the target coal seam, which is obtained through instantaneous pump shutdown pressure analysis of small-scale fracturing tests or downhole stress relief methods. The Poisson's ratio of the target coal seam is dimensionless and is the average value of the ratio of transverse strain to longitudinal strain in the uniaxial compression test of the coal sample. This is a fracture morphology correction factor, dimensionless, with a value ranging from 0.85 to 1. The specific value is determined based on the fracture density of the target coal seam: when the fracture density is greater than ten fractures per meter... Take one example; when the fracture density is between five and ten fractures per meter, Take 0.92; when the fracture density is less than five fractures per meter, The value is set to 0.85. The fracture morphology correction factor is based on the fact that the higher the fracture density, the weaker the control effect of the direction of the primary fractures in the coal seam on the propagation direction of the hydraulic fractures, and the hydraulic fractures tend to form regular elliptical fractures, so the fracture morphology correction factor approaches one; the lower the fracture density, the stronger the inducing effect of the primary fractures on the propagation of the hydraulic fractures, the fracture morphology deviates from the ideal ellipse, and the value of the fracture morphology correction factor decreases.

[0046] In determining the movement distance of the double packer along the fracturing branch hole based on the fracture propagation radius and the correction value of the initiation pressure of the next fracturing segment, the next fracturing segment refers to the second fracturing segment that is adjacent to the first fracturing segment and closer to the borehole orifice. The correction value of the initiation pressure is obtained based on the measured value of the coal seam in-situ stress in the depth range where the second fracturing segment is located. The measured value of the coal seam in-situ stress is obtained by conducting hydraulic fracturing stress testing in the fracturing branch hole before hydraulic fracturing operations. The specific method of hydraulic fracturing stress testing is as follows: after the fracturing branch hole is constructed to the design depth, the drill string is withdrawn, and the straddle packer of the hydraulic fracturing stress testing system is lowered. Small-scale fracturing tests are conducted at multiple depth points in the fracturing branch hole, and the fracturing pressure, re-tension pressure, and instantaneous pump stop pressure are recorded at each test point. The maximum horizontal principal stress is calculated from the fracturing pressure and re-tension pressure, and the minimum horizontal principal stress is determined from the instantaneous pump stop pressure. The minimum horizontal principal stress at each test point within the depth range of the fracturing branch hole is linearly interpolated along the depth to generate a curve of the minimum horizontal principal stress versus depth. The calculation method for the correction value of the initiation pressure of the second fracturing stage is as follows: extract the minimum horizontal principal stress value corresponding to the midpoint depth of the second fracturing stage, multiply it by the stress concentration influence coefficient, which is between 1.05 and 1.15, and then superimpose the pore pressure of the target coal seam to obtain the correction value of the initiation pressure. The range of the stress concentration influence coefficient is based on the theoretical solution of the borehole stress concentration effect, considering the stress distribution around the elliptical borehole. When the ratio of the diameter of the fracturing branch hole to the outer diameter of the upper and lower packer sleeves is close to one, it is taken as 1.05. The larger the diameter ratio, the higher the value.

[0047] The determination of the moving distance of the dual packer along the fracturing branch hole must meet two constraints: First, after moving, the lower packer of the dual packer should be positioned at the lower boundary of the second fracturing section. The lower boundary of the second fracturing section is determined based on the starting point of the corresponding fracturing depth interval of the second fracturing section. Simultaneously, a safe setting distance should be maintained between this lower boundary and the fracture propagation influence zone of the first fracturing section. Second, after moving, the upper packer of the dual packer should not exceed the orifice protection section of the fracturing branch hole. The moving distance is calculated as follows: the difference between the starting depth of the second fracturing section and the setting point depth of the lower packer of the first fracturing section is taken as the basic moving amount. The basic moving amount is equal to the reference length of the second fracturing section minus the overlap length between the first and second fracturing sections. If the measured value of the fracture propagation radius exceeds the expected range, the basic movement amount is corrected. The correction rule is as follows: when the fracture propagation radius is greater than 120% of the expected fracture propagation radius, the overlap length is increased by 50% of the excess fracture propagation radius, so that the lower packer moves away from the fracture influence zone of the first fracturing section to ensure the integrity of the borehole wall in the setting section and the sealing effect of the packer; when the fracture propagation radius is less than 80% of the expected fracture propagation radius, the overlap length is reduced by 30% of the insufficient fracture propagation radius, so that the lower packer is appropriately closer to the insufficiently propagated zone of the first fracturing section to facilitate the penetration of the fracture towards the first fracturing section during the second fracturing section.

[0048] During the process of raising the drill pipe to move the double packers to the second fracturing section according to the moving distance, the drilling rig operator monitors the raising stroke of the drill pipe in real time in the driller's cabin using a depth counter. The raising operation adopts a slow and uniform raising method, and the raising speed is controlled not to exceed five meters per minute. When the depth counter reading shows that the moving distance has been reached, the raising is stopped, the drilling rig brake device is locked, and the suspended weight and depth reading at this time are recorded as the reference data for the setting of the packers in the second fracturing section. The specific operation method for setting the upper and lower packers of the double packers to the upper and lower boundaries of the second fracturing section is as follows: confirm that the depth of the lower packer is consistent with the lower boundary depth of the second fracturing section, and the depth of the upper packer is consistent with the upper boundary depth of the second fracturing section. Hydraulic oil is injected into the drill pipe. The hydraulic oil enters the rubber sleeve chamber of the upper and lower packers through the central tube of the double packers, and the pressure causes the rubber sleeve to expand and adhere to the wall of the fracturing branch hole. The setting pressure is determined based on the packer's technical specifications, typically ranging from 90% to 110% of the packer's rated setting pressure. After setting, the wellhead blowout preventer is closed, the pressure relief valve is opened, and the seal between the upper and lower packers is confirmed. The seal is confirmed by pressurizing the packer's center tube to the predetermined test pressure, shutting in the well for 30 minutes, and recording the pressure drop. If the pressure drop does not exceed 5% of the test pressure within 30 minutes, the setting is considered successful. After successful setting, the closed fracturing space of the second fracturing stage is formed, providing a sealed working environment for subsequent fracturing fluid injection.

[0049] Example 4: In specific implementation, please refer to Figure 5 The rated output pressure and rated flow rate of the high-pressure nitrogen injection equipment are obtained by consulting the equipment nameplate parameters and technical specifications. The high-pressure nitrogen injection equipment adopts a skid-mounted high-pressure nitrogen booster injection system, which consists of a liquid nitrogen storage tank, a cryogenic liquid nitrogen pump, a vaporizer, a booster compressor, and an output control unit. The rated output pressure refers to the highest continuously available exhaust pressure at the booster compressor outlet, measured in megapascals (MPa), and the nameplate value is taken from the equipment's factory performance test report. The rated flow rate refers to the mass flow rate of nitrogen that the equipment can deliver per unit time under rated output pressure conditions, measured in kilograms per minute (kg / min), and the nameplate value is taken from the calibration results of the nitrogen mass flow meter under standard operating conditions.

[0050] The initial injection pressure and flow rate are set according to the rated output pressure and rated flow rate as follows: the initial injection pressure is set to 60% of the rated output pressure, and the initial injection flow rate is set to 40% of the rated flow rate. These percentages are determined based on the principle of matching the initial injection conditions of the injection branch orifice with the target coal seam. Considering that the injection branch orifice is filled with atmospheric pressure air or low-pressure methane gas before switching to high-pressure nitrogen injection, excessively high pressure in the initial injection stage may cause impact loads on the orifice pipeline and packer. Excessively high flow rate may cause nitrogen to rapidly occupy the coal seam permeability channels near the injection branch orifice wall, forming a gas blockage and hindering subsequent nitrogen from displacing the fracturing fluid into the deeper coal seam. Therefore, a medium-to-low ratio of initial parameters is used to establish a stable injection flow channel.

[0051] The level of residual fracturing fluid in the fracturing branch hole is obtained through a fluid level monitoring system. This system includes a level sensor installed at the orifice of the fracturing branch hole. The level sensor is a submersible pressure level gauge, with its probe positioned below the fluid level inside the branch hole. The fluid level is calculated by measuring the hydrostatic pressure of the fluid column. The signal from the level sensor is converted into a digital signal by the orifice data acquisition module and transmitted to the ground monitoring host via an intrinsically safe communication cable. The ground monitoring host records the fluid level value once per minute. When the level of residual fracturing fluid in the branch hole drops below the orifice but the level sensor probe remains submerged, the fluid level is directly read from the sensor. When the fluid level continues to drop, causing the level sensor probe to become exposed, an acoustic level gauge is used to emit acoustic pulses from the orifice and receive the reflected echoes from the fluid surface. The fluid level is calculated by the round-trip time of the acoustic pulses and the velocity of sound inside the orifice. The acoustic level gauge is installed at the orifice tee of the fracturing branch hole. Before measurement, the sound velocity is calibrated by passing through an empty section of known length.

[0052] The specific method for calculating the residual fracturing fluid level drop rate based on fluid level monitoring data is as follows: Divide the difference in fluid level height between two consecutive recording times by the time interval between the two recording times to obtain the average fluid level drop rate within that time interval, expressed in meters per minute (m / min). The time interval between the two consecutive recording times used in the calculation is five minutes. When the fluid level drop rate slows down, the time interval is extended to ten minutes to improve calculation stability. The fluid level drop rate reflects the rate at which residual fracturing fluid is lost into the target coal seam fractures. Under the condition that the fracturing branch orifice is connected to the fracture network of the target coal seam, the fluid level drop is mainly caused by the fracturing fluid seeping into the deeper parts of the coal seam fractures under the combined action of gravity and capillary force. The seepage rate is positively correlated with the permeability of the target coal seam and the fracture aperture.

[0053] The process of calculating the minimum driving pressure required for high-pressure nitrogen displacement of residual fracturing fluid based on the fluid level drop rate and the permeability of the target coal seam is based on the initiation pressure gradient theory of immiscible displacement. The permeability of the target coal seam is obtained through water injection pressure drop tests during the fracturing branch hole construction. The water injection pressure drop test is conducted after all the staged reverse hydraulic fracturing operations are completed and before the gas injection operation begins. Specifically, a certain volume of clean water is injected into the fracturing branch hole, the pump is stopped, the pressure drop curve is recorded, and the average effective permeability of the target coal seam is obtained by fitting the pressure drop curve.

[0054] The formula for calculating the minimum driving pressure required for high-pressure nitrogen displacement of residual fracturing fluid is as follows:

[0055]

[0056] in, This represents the minimum driving pressure required for high-pressure nitrogen to displace residual fracturing fluid, expressed in megapascals (MPA). This represents the pore pressure of the target coal seam, in megapascals (MPa), and is determined by the measured value of the coal seam gas pressure. This represents the surface tension between high-pressure nitrogen and residual fracturing fluid, expressed in millinewtons per meter (mN / m). The contact angle of the high-pressure nitrogen-residual fracturing liquid system on the target coal and rock surface is expressed in degrees. The average pore radius of the target coal seam is expressed in micrometers. The inertial displacement drag coefficient is dimensionless. This indicates the dynamic viscosity of the residual fracturing fluid, measured in millipascals per second. This indicates the rate of drop in the residual fracturing fluid level, expressed in meters per minute. The effective permeability of the target coal seam is expressed in millidarcy. This represents the average seepage path length of the residual fracturing fluid displaced by high-pressure nitrogen, expressed in meters. It is determined based on the spatial distance between the injection branch hole and the final position of the fracturing branch hole, as well as the extension direction of the main fracture in the target coal seam, and is taken as the fracture connectivity radius. The value is 0.6 to 1.2 times that of the injection branch hole and the fracturing branch hole. The upper limit is taken when the difference in the final hole level between the injection branch hole and the fracturing branch hole is large, and the lower limit is taken when the fracture connectivity is good.

[0057] The initial injection pressure is compared with the minimum driving pressure. If the initial injection pressure is less than the minimum driving pressure, the initial injection pressure is increased to a level above the minimum driving pressure. The increased injection pressure is equal to the minimum driving pressure multiplied by one. A safety factor of 1.1 to 1.3 is used to ensure a reasonable driving margin while overcoming the minimum driving pressure. If the initial injection pressure is greater than or equal to the minimum driving pressure, the initial injection pressure remains unchanged. The injection pressure is adjusted by regulating the output frequency of the booster compressor inverter in the high-pressure nitrogen injection equipment. The change in output pressure corresponding to each Hz frequency adjustment is given by the equipment's pressure-frequency characteristic curve.

[0058] The method for adjusting the initial injection flow rate based on the real-time changes in the liquid level drop rate is as follows: When the liquid level drop rate continuously increases over two consecutive monitoring periods, it indicates that the residual fracturing fluid is being lost to the coal seam at an accelerated rate. In this case, the initial injection flow rate is increased by 10% to 20% to dynamically match the injection rate of high-pressure nitrogen with the fracturing fluid loss rate. When the liquid level drop rate continuously decreases over two consecutive monitoring periods, it indicates that the loss of residual fracturing fluid is weakening. In this case, the initial injection flow rate is decreased by 5% to 15% to avoid excessive nitrogen injection causing excessive pressure buildup. The above adjustment operations generate a dynamic injection parameter sequence, which is an array arranged in chronological order. Each element in the array contains the injection pressure setpoint and injection flow rate setpoint for the corresponding time period.

[0059] The process of injecting high-pressure nitrogen into the target coal seam in segments through injection branch holes according to the dynamic injection parameter sequence is as follows: Connect the orifice of the injection branch hole to the output pipeline of the high-pressure nitrogen injection equipment via a high-pressure metal hose. Open the injection valve at the orifice of the injection branch hole, start the high-pressure nitrogen injection equipment, and begin injection according to the first set of injection pressure and flow rate settings in the dynamic injection parameter sequence. Each injection segment lasts three to ten minutes, with the segment length determined based on the update cycle of the parameters in the dynamic injection parameter sequence. During each injection segment, the injection pressure is monitored in real time by a pressure transmitter and a mass flow meter installed at the orifice of the injection branch hole. The pressure transmitter samples five times per second, and the mass flow meter samples twice per second.

[0060] The method for adjusting the injection duration of the current segment based on the injection pressure change rate is as follows: At the beginning of each injection segment, the initial injection pressure value is recorded. During the injection process, the injection pressure change rate is continuously calculated, defined as the change in injection pressure per unit time, expressed in megapascals per minute (MPa). When the injection pressure change rate is below 0.05 MPa per minute for two consecutive sampling periods, it indicates that the injection pressure is stabilizing, and high-pressure nitrogen has established a relatively stable displacement front within the target coal seam fractures. At this point, the current segment of injection can be terminated, and the next set of parameters in the dynamic injection parameter sequence can be switched to begin the next segment. When the injection pressure change rate exceeds 0.2 MPa per minute and continues to rise, it indicates a rapid increase in injection pressure, possibly caused by the fracturing fluid blocking the permeation channels near the injection branch orifice or fracture closure. In this case, the injection duration of the current segment is shortened to 50% of the original time, and the next set of dynamic injection parameters with a higher injection pressure value is switched ahead of schedule to overcome the blockage. Repeat the above-mentioned segmented injection and pressure change rate monitoring process until the cumulative mass of injected high-pressure nitrogen reaches the predetermined total injection volume. The predetermined total injection volume is determined by multiplying the estimated volume of residual fracturing fluid in the fracturing branch hole by the displacement ratio coefficient, which is between 1.5 and 2.5.

[0061] Example 5: In practice, closing the output valve of the high-pressure nitrogen injection equipment is accomplished by operating the output control unit of the high-pressure nitrogen injection equipment. After receiving the stop injection command, the output control unit first cuts off the power supply to the booster compressor's drive motor, and then sequentially closes the pneumatic shut-off valve and manual ball valve on the output pipeline to ensure that the high-pressure nitrogen flow path is completely cut off. After the output valve is closed, the high-pressure metal hose between the high-pressure nitrogen injection equipment and the injection branch port is in a depressurized state. The residual nitrogen in the pipeline is vented to the safety vent pipe by opening the depressurization bypass valve. After the pressure gauge reading returns to zero, the connection between the high-pressure metal hose and the injection branch port is disconnected.

[0062] The specific method for connecting the orifice of the gas injection branch hole to the inlet of the extraction pipeline is as follows: Connect the quick-connect fitting at the inlet of the extraction pipeline to the flange at the orifice of the gas injection branch hole, and secure it with a negative pressure resistant gasket and clamps to form a sealed connection. The extraction pipeline is equipped with a vacuum pump and a gas-liquid separator. The vacuum pump is a water ring vacuum pump, and its rated pumping capacity is selected based on the expected maximum mixed fluid output of the gas injection branch hole. The ultimate vacuum degree of the water ring vacuum pump is not lower than -95 kPa. The gas-liquid separator adopts a combined structure of cyclone separation and wire mesh capture, and is arranged on the inlet side of the vacuum pump. The processing capacity of the gas-liquid separator matches the rated pumping capacity of the vacuum pump. From the orifice of the gas injection branch hole to the inlet of the vacuum pump, the extraction pipeline is sequentially arranged with a shut-off valve, a filter, a gas-liquid separator, and a check valve. The outlet of the vacuum pump is connected to the gas collection pipeline, which leads to the mine's permanent gas extraction system.

[0063] Before applying negative pressure extraction force to the gas injection branch hole by starting the vacuum pump, the extraction pipeline is checked for air tightness. The air tightness check method is to close the shut-off valve at the gas injection branch hole orifice, start the vacuum pump to evacuate the pipeline to -80 kPa, and observe the vacuum level after stopping the pump. If the decrease in vacuum level does not exceed 5 kPa within 10 minutes, it is considered qualified. After the air tightness check is qualified, the shut-off valve at the gas injection branch hole orifice is opened, the vacuum pump is started, and the speed of the vacuum pump is adjusted by the frequency converter so that the extraction negative pressure value at the gas injection branch hole orifice gradually reaches the initial set value. The initial extraction negative pressure value is set to 30% to 50% of the original gas pressure of the target coal seam. The original gas pressure of the target coal seam is provided by the coal seam gas parameter measurement borehole. After applying negative pressure extraction force, the mixed fluid in the fracture system of the target coal seam flows to the bottom of the gas injection branch hole under the drive of the pressure gradient. The mixed fluid includes the high-pressure nitrogen injected in the early stage, the fracturing fluid remaining from hydraulic fracturing, and the coal seam desorbed gas from the target coal seam matrix.

[0064] During the extraction of the mixed fluid through the gas injection branch orifice, monitoring points for mixed fluid parameters are set up on the extraction pipeline at the orifice opening. These monitoring points are equipped with gas flow meters, liquid flow meters, pressure transmitters, and concentration sensors. The gas flow meters are thermal mass flow meters used to measure the instantaneous and cumulative mass flow rates of the gas phase components in the mixed fluid; the liquid flow meters are Coriolis mass flow meters used to measure the instantaneous and cumulative mass flow rates of the liquid phase components; the pressure transmitters are used to record the extraction negative pressure value in real time; and the concentration sensor is an infrared methane sensor used to detect the concentration of methane in the gas phase components. The data collected by each sensor is aggregated and transmitted to the ground monitoring host via a mine data acquisition module.

[0065] The specific process for introducing the mixed fluid into the gas-liquid separator for gas-liquid separation is as follows: The mixed fluid enters the gas-liquid separator after passing through the injection branch orifice shut-off valve and filter. The tangential inlet of the gas-liquid separator causes the fluid to rotate at high speed. Under the action of centrifugal force, the liquid droplets are thrown against the separator wall and settle along the wall. The gaseous components escape upward from the central tube, pass through the wire mesh trapping layer for further separation of fine droplets, and are then discharged. The separated liquid fracturing fluid is collected in a storage tank below the gas-liquid separator. The storage tank is equipped with a level gauge and a drain valve. When the liquid level reaches 80% of the storage tank's volume, the shut-off valve upstream of the drain valve is closed, and the liquid fracturing fluid is discharged to the wastewater collection truck through the drain valve. The separated gaseous mixture enters the gas collection pipeline from the gas-liquid separator outlet through a one-way valve. The gas collection pipeline is connected to the main gas extraction pipeline of the mine. The methane component contained in the gaseous mixture is transported to the surface gas utilization station or the venting system.

[0066] The recording of the extraction negative pressure value and extraction gas volume variation curve of the gas injection branch orifice under extraction conditions is completed by the data acquisition software of the ground monitoring host. The extraction negative pressure value is taken from the second-level sampling data of the pressure transmitter at the gas injection branch orifice, and an average value is calculated every minute as the extraction negative pressure record value for that minute. The extraction gas volume variation curve is plotted with time as the horizontal axis and cumulative extraction gas volume as the vertical axis. At the same time, the instantaneous extraction gas volume variation curve is plotted, which is the average value of the gas flow meter per minute. The monitoring host processes the extraction gas volume variation curve in real time, calculates the first derivative of the instantaneous extraction gas volume with time, and obtains the extraction gas volume change rate.

[0067] The method for determining whether the gas desorption rate of the target coal seam has reached the attenuation threshold based on the gas extraction volume change curve is as follows: During the phase where the gas extraction volume change curve tends to flatten, the moving average of the gas extraction volume change rate is calculated over a set time window of ten minutes. When the moving average of the gas extraction volume change rate over three consecutive time windows is lower than the preset attenuation threshold slope, the gas desorption rate of the target coal seam is determined to have reached the attenuation threshold. The formula for calculating the attenuation threshold slope is:

[0068]

[0069] in, This represents the attenuation threshold slope, expressed in cubic meters per minute. This represents the average rate of change of extracted gas volume during the initial extraction phase, expressed in cubic meters per minute. The initial extraction phase is defined as the period from the first ten minutes to the twentieth minute after the start of extraction, and the arithmetic mean of the rate of change of extracted gas volume during this period is taken. This represents the attenuation ratio coefficient, which is dimensionless and ranges from 0.1 to 0.2. The specific value is determined based on the effective permeability of the target coal seam: when the effective permeability of the target coal seam is greater than ten millidarcy... Take 0.1; when the effective permeability of the target coal seam is between 5 millidarcy and 10 millidarcy, Take 0.15; when the effective permeability of the target coal seam is less than 5 millirs, Take 0.2. The attenuation ratio coefficient increases as the effective permeability of the target coal seam decreases. This is because the gas desorption and diffusion rate is slower in low-permeability coal seams, and the initial decrease in the amount of extracted gas is relatively small. Therefore, a wider attenuation threshold must be used to avoid misjudging and prematurely ending the extraction stage.

[0070] When the gas desorption rate reaches the attenuation threshold, perform the operations of turning off the vacuum pump and reconnecting the gas injection branch borehole to the high-pressure nitrogen injection equipment. The operation steps for turning off the vacuum pump are: first close the stop valve at the orifice of the gas injection branch borehole, then stop the vacuum pump motor, then close the valve on the air inlet pipeline and the valve on the air outlet pipeline of the vacuum pump, perform nitrogen replacement on the extraction pipeline, and then disconnect the connection with the orifice of the gas injection branch borehole. The steps for reconnecting the gas injection branch borehole to the high-pressure nitrogen injection equipment are: connect one end of the high-pressure metal hose to the output interface of the high-pressure nitrogen injection equipment, and connect the other end to the orifice flange of the gas injection branch borehole; after tightening, perform a air tightness test on the connecting pipeline, the air tightness test pressure shall be 1.1 times the predetermined secondary injection pressure value, and the test is qualified if the pressure drop does not exceed 2% of the test pressure after pressure holding for five minutes.

[0071] The process of re-injecting high-pressure nitrogen into the target coal seam according to the secondary injection pressure value is: start the high-pressure nitrogen injection equipment and set the output pressure to the secondary injection pressure value. The determination method of the secondary injection pressure value is: the secondary injection pressure value of the first alternating cycle is 80% of the maximum injection pressure in the initial high-pressure nitrogen injection stage; the secondary injection pressure values of subsequent alternating cycles decrease sequentially. When injecting high-pressure nitrogen, the equipment operates in constant pressure injection mode. After the injection pressure reaches the set secondary injection pressure value, continuous injection is maintained, the continuous injection duration is set to 30 minutes or dynamically adjusted according to the length of the platform period after the gas injection pressure is stabilized. During the high-pressure nitrogen injection process, the fracture system of the target coal seam is subjected to secondary pressure loading, and the additional stress concentration areas caused by local fracture closure due to early extraction and gas desorption shrinkage will re-initiate and expand under the action of periodic pressure fluctuation, so as to realize the third fracturing of the target coal seam.

[0072] After three fracturing operations, the gas injection branch hole is switched back to extraction mode. The switching procedure is the same as the previous switch from high-pressure nitrogen injection to extraction. Multiple alternating pressure and extraction operations are performed in an alternating cycle, with each cycle consisting of one high-pressure nitrogen injection phase and one extraction phase. The injection pressure and extraction negative pressure values ​​for each alternating cycle are dynamically adjusted based on the gas extraction concentration of the previous alternating cycle. The specific adjustment rules are as follows: obtain the average gas extraction concentration during the extraction phase of the previous alternating cycle. When the average gas extraction concentration decreases by more than 10% compared to the average concentration of the previous alternating cycle, the secondary injection pressure value of the current alternating cycle is reduced by 5% to 8% based on the secondary injection pressure value of the previous alternating cycle, while the initial extraction negative pressure value of the current alternating cycle is increased by 3% to 5% based on the initial extraction negative pressure value of the previous alternating cycle. When the average gas extraction concentration decreases by no more than 10%, the reduction in the secondary injection pressure value is 3%, and the increase in the initial extraction negative pressure value is 2%. The aforementioned dynamic adjustment results in a gradual decrease in the secondary injection pressure and a gradual increase in the extraction negative pressure during each alternating cycle, creating an asymmetric pressure fluctuation load. The characteristics of this asymmetric pressure fluctuation load are a gradual decrease in the peak pressure during the high-pressure injection phase and a gradual increase in the absolute value of the negative pressure during the negative pressure extraction phase. Under this loading mode, the target coal seam experiences cyclic stress disturbances of varying amplitudes, leading to a gradual superposition of damage from newly formed and existing fractures, which in turn promotes the continuous desorption of residual gas and maintains the enhanced extraction effect. The termination condition for the alternating cycle operation is: when the average gas extraction concentration during a certain extraction phase decreases to less than 10% of the average gas extraction concentration during the initial extraction phase, the alternating cycle operation is stopped, and the conventional gas extraction management procedure is initiated.

[0073] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any changes or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application.

Claims

1. A method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping, characterized in that, The method includes: In the target coal seam, directional long boreholes are drilled, and fracturing branch holes and gas injection branch holes are arranged according to the drilling trajectory of the directional long boreholes and the occurrence parameters of the target coal seam. The fracturing branch hole and the gas injection branch hole are sealed by double packers respectively. Segmented reverse hydraulic fracturing operation is performed in the fracturing branch hole. The original fracture network of the target coal seam is initiated and expanded segment by segment by high-pressure water injection pump. After the segmented reverse hydraulic fracturing operation reaches the predetermined water injection volume, the hydraulic fracturing operation is stopped, the gas injection branch hole is connected to the high-pressure nitrogen injection equipment, and high-pressure nitrogen is injected into the target coal seam through the gas injection branch hole. The driving effect of the high-pressure nitrogen is used to backflow the fracturing fluid in the fracturing branch hole, and the pressure pulse of the high-pressure nitrogen is used to perform secondary fracturing on the target coal seam. After the high-pressure nitrogen injection reaches the predetermined injection volume, the high-pressure nitrogen injection is stopped, and the gas injection branch hole is switched to the extraction state. The mixed fluid in the target coal seam is discharged in a negative pressure extraction manner. The target coal seam is subjected to three fracturing operations through alternating pressure and extraction to maintain a long-term high-efficiency extraction state.

2. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping enhancement according to claim 1, characterized in that, Based on the borehole trajectory of the directional long borehole and the occurrence parameters of the target coal seam, fracturing branch holes and gas injection branch holes are arranged, including: Obtain the drilling trajectory parameters of the directional long borehole, including the drilling azimuth angle, drilling inclination angle, and drilling depth; The development direction of the main fractures and the distribution of the coal seam thickness in the target coal seam are determined based on the occurrence parameters of the target coal seam. The occurrence parameters include the coal seam thickness, the coal seam dip angle, the fracture density, and the fracture orientation. Based on the borehole trajectory parameters and the occurrence parameters, the fracturing branch holes and the gas injection branch holes are set in a direction that forms a predetermined angle with the development direction of the main fracture, so that the fracturing branch holes and the gas injection branch holes are alternately arranged along the axial direction of the directional long borehole, and the final positions of the fracturing branch holes and the gas injection branch holes are distributed in different thickness layers of the target coal seam.

3. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping enhancement according to claim 2, characterized in that, Performing staged reverse hydraulic fracturing operations within the fracturing branch hole includes: The drilling depth of the fracturing branch hole and the fracturing initiation pressure threshold of the target coal seam are obtained. The fracturing branch hole is divided into multiple fracturing segments according to the drilling depth, and each fracturing segment corresponds to a fracturing depth range. The double packer is lowered to the first fracturing section furthest from the orifice. The high-pressure water injection pump is started to inject fracturing fluid into the first fracturing section. The injection pressure of the first fracturing section is monitored in real time until the injection pressure reaches the fracturing initiation pressure threshold and continues to initiate and propagate fracturing, at which point the injection is stopped. After completing the fracturing operation of the first fracturing section, the double packer is adjusted to the next adjacent fracturing section via the drill pipe. The operation of injecting fracturing fluid and monitoring the injection pressure is repeated until the fracturing operation of all the fracturing sections is completed, forming a reverse fracturing sequence from the bottom of the hole to the orifice.

4. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping enhancement according to claim 3, characterized in that, After completing the fracturing operation of the first fracturing section, the double packer is adjusted via the drill pipe to the adjacent next fracturing section, including: Record the pump stop pressure and the cumulative injection volume of fracturing fluid when the first fracturing stage completes the initiation and propagation. Calculate the fracture propagation radius corresponding to the first fracturing stage based on the pump stop pressure and the cumulative injection volume of fracturing fluid. The moving distance of the double packer along the fracturing branch hole is determined based on the fracture propagation radius and the correction value of the initiation pressure of the next fracturing section. The correction value of the initiation pressure is obtained based on the measured value of the coal seam in the depth range where the next fracturing section is located. The drill pipe is lifted according to the specified moving distance, which drives the double packer to move to the next fracturing section. The upper and lower packers of the double packer are respectively positioned at the upper and lower boundaries of the next fracturing section, forming a closed fracturing space for the next fracturing section.

5. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping enhancement according to claim 1, characterized in that, Injecting high-pressure nitrogen into the target coal seam through the injection branch hole includes: Obtain the rated output pressure and rated flow rate of the high-pressure nitrogen injection equipment, and set the initial injection pressure value and initial injection flow rate value based on the rated output pressure and rated flow rate; Based on the liquid level of the residual fracturing fluid in the fracturing branch hole and the permeability of the target coal seam, the initial injection pressure and the initial injection flow rate are dynamically adjusted to generate a dynamic injection parameter sequence. According to the dynamic injection parameter sequence, high-pressure nitrogen is injected into the target coal seam in segments through the injection branch holes. During each injection segment, the injection pressure change rate is monitored, and the injection duration of the current segment is adjusted according to the injection pressure change rate until the predetermined total injection volume is reached.

6. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping as described in claim 5, characterized in that, Based on the residual fracturing fluid level in the fracturing branch hole and the permeability of the target coal seam, the initial injection pressure and the initial injection flow rate are dynamically adjusted, including: Acquire liquid level monitoring data in the fracturing branch hole, calculate the liquid level drop rate of the residual fracturing fluid based on the liquid level monitoring data, and the liquid level drop rate reflects the filtration rate of the residual fracturing fluid into the target coal seam fracture; Based on the liquid level drop rate and the permeability of the target coal seam, calculate the minimum driving pressure required for high-pressure nitrogen to displace the residual fracturing fluid. The initial injection pressure value is compared with the minimum driving pressure value. If the initial injection pressure value is less than the minimum driving pressure value, the initial injection pressure value is increased to above the minimum driving pressure value, and the initial injection flow rate is adjusted accordingly based on the real-time change in the liquid level drop rate.

7. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping enhancement according to claim 1, characterized in that, Switching the gas injection branch hole to the extraction state, and discharging the mixed fluid in the target coal seam using negative pressure extraction, includes: Close the output valve of the high-pressure nitrogen injection equipment and connect the orifice of the injection branch hole to the inlet of the extraction pipeline, which is equipped with a vacuum pump and a gas-liquid separator. The vacuum pump is started to apply negative pressure extraction force to the gas injection branch hole, and the mixed fluid in the target coal seam is extracted through the gas injection branch hole. The mixed fluid contains high-pressure nitrogen, residual fracturing fluid and coal seam desorption gas. The mixed fluid is introduced into the gas-liquid separator for gas-liquid separation. The separated liquid fracturing fluid is collected in a storage tank, and the separated gaseous mixed gas is transported to a gas collection pipeline.

8. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping as described in claim 7, characterized in that, The method of fracturing the target coal seam three times through alternating pressure and pumping operations to maintain a long-term, high-efficiency pumping state includes: Record the negative pressure value and gas volume change curve of the gas injection branch hole under the extraction state, and determine whether the gas desorption rate of the target coal seam has reached the attenuation threshold based on the gas volume change curve. When the gas desorption rate reaches the attenuation threshold, the vacuum pump is turned off and the gas injection branch hole is reconnected to the high-pressure nitrogen injection device. High-pressure nitrogen is injected into the target coal seam again according to the secondary injection pressure value to form periodic pressure fluctuations to fracturing the target coal seam three times. After the three fracturing operations are completed, the gas injection branch hole is switched back to the extraction state, and multiple pressure-extraction alternating operations are performed in an alternating cycle. The injection pressure value and extraction negative pressure value of each alternating cycle are dynamically adjusted according to the gas extraction concentration of the previous alternating cycle.

9. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping as described in claim 3, characterized in that, The fracturing depth ranges between two adjacent fracturing sections partially overlap, and the overlap length is determined according to the fracture connectivity radius of the target coal seam to ensure the continuous connection of the fracture network between adjacent fracturing sections.

10. The method for directional long-hole multi-stage hydraulic fracturing and high-pressure nitrogen displacement pumping enhancement according to claim 8, characterized in that, In each alternating cycle, the secondary injection pressure value decreases successively, while the extraction negative pressure value increases successively, so as to form an asymmetric pressure fluctuation load to cumulatively damage and fracture the target coal seam.

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