Wellbore multilayer complex leakage double-channel while-drilling adaptive plugging device and method

Abstract

This invention relates to the field of oil and gas drilling engineering technology, and discloses a dual-channel adaptive plugging device and method for complex multi-layered wellbore leakage. The device comprises a dual-channel connector, a dual-channel drill pipe, a bypass sub, and a lower drill string assembly connected in sequence, forming physically isolated inner and outer channels. The method includes: switching the dual-injection dual-channel operating state; establishing a reference hydraulic pressure loss model for the inner and outer channels; applying a displacement step disturbance to the inner and outer channels; differentially identifying and calculating the relative leakage index of the interval; determining the target leakage interval and the safe injection window; pulse-injecting plugging slurry into the outer channel; synchronously injecting drilling fluid into the inner channel and dynamically matching the annular flow velocity; after replacing the plugging slurry, re-performing differential identification to determine the plugging effect; and resuming normal drilling after passing pressure verification. This invention achieves quantitative identification of leakage intervals and anti-clogging grouting plugging of drill string assemblies without tripping in or out of the drill string through in-situ switching of dual channels, isobaric registration differential identification, and dynamic flow velocity matching technology.

Description

Technical Field

[0001] This invention relates to the field of oil and gas drilling engineering technology, specifically to a dual-channel adaptive plugging device and method for multi-layer complex leakage in wellbores. Background Technology

[0002] Wellbore leakage has always been a technical challenge in oil and gas drilling engineering. Wellbore leakage is mainly classified into permeable leakage, fracture leakage, cavernous leakage, and rupture leakage according to its scale and cause. With the acceleration of exploration and development of deep-earth, deep-sea, and unconventional oil and gas resources, multiple layers of leakage in the wellbore are superimposed under complex formations and pressure systems, resulting in inter-layer interference. When faced with complex multi-layer leakage in the wellbore, conventional single-channel drill string assemblies are difficult to handle both drilling and grouting conditions. After formation leakage is discovered, drilling operations need to be stopped, the conventional single-channel drill string assemblies need to be pulled out of the wellbore, and a special plugging string needs to be run in for grouting and sealing. After the sealing operation is completed, the conventional single-channel drill string assemblies need to be run in again to resume drilling. Frequent tripping of drill string assemblies increases the time for leakage treatment, and increases the risk and cost of drilling engineering.

[0003] In complex, multi-layered leakage situations within a wellbore, leakage channels in different leakage formations span multiple scales and exhibit formation pressure differences. Existing leakage identification methods rely on macroscopic leakage flow rate changes across the entire wellbore at the wellhead, making it difficult to pinpoint specific leakage layers and quantify the degree of local leakage without interrupting drilling. The leakage response of a specific leakage interval is affected by background leakage in the shared well section above that interval, preventing existing leakage identification methods from accurately obtaining the relative leakage characteristics and equivalent leakage initiation pressure of a specific leakage interval. Furthermore, the lack of quantitative data to support subsequent plugging operations in the target leakage interval makes conventional plugging systems and techniques insufficient for sealing complex, multi-layered leakage formations.

[0004] During the grouting and plugging stage, conventional plugging operations lack dynamic matching methods for downhole pressure and wellbore annular flow velocity. The plugging slurry contains a large number of solid particles. If the annular flow velocity in the target leakage zone is lower than the gravity settling velocity of the solid particles in the plugging slurry during the grouting process, the solid particles will settle and cause mechanical blockage inside the drill string assembly or plugging tool. If the annular flow velocity in the target leakage zone is higher than the critical flow velocity of the plugging structure to resist erosion, the wellbore fluid erosion will damage the original formation pressure-bearing structure in the target leakage zone as well as the newly generated plugging structure, leading to formation plugging failure and wellbore instability risks. Summary of the Invention

[0005] To address the shortcomings of existing technologies, this invention provides a dual-channel adaptive plugging device and method for complex multi-layer wellbore leakage, which solves the technical problems of frequent tripping of conventional single-channel drill string assemblies, difficulty in quantifying and identifying specific leakage intervals due to background leakage interference, and lack of dynamic matching of annular flow velocity in grouting leading to tool blockage or erosion damage to the plugging structure under complex multi-layer wellbore leakage conditions.

[0006] To achieve the above objectives, the present invention provides the following technical solution: The first aspect of this invention provides a method for adaptive plugging of complex multi-layered leakage in wellbores via dual-channel drilling, the method comprising: The dual-channel drill string assembly is lowered into the well section with no leakage in the wellbore, and switched to the dual-injection dual-channel working state. Fluid is injected into the inner channel and the outer channel respectively, and the benchmark hydraulic pressure loss model of the inner channel and the outer channel is established. The bypass section is moved to the well section to be identified for leakage. Based on the benchmark hydraulic pressure loss model, a displacement step disturbance is applied to the inner and outer channels respectively to form an equal equivalent annular pressure increment and obtain the leakage response. The interval relative leakage index of the well section between the drill bit and the nozzle is calculated. Candidate leakage intervals are screened based on the relative leakage index of the intervals, and the equivalent leakage initiation pressure is tested. The blocking priority value is calculated, and the target leakage interval is determined. Calculate the lower limit and upper limit of the allowable injection pressure for the target leakage zone. Between the lower limit and the upper limit of the allowable injection pressure, inject plugging slurry into the target leakage zone through the outer channel in a pulse. Adjust the drilling fluid discharge rate injected synchronously through the inner channel based on the annular flow velocity of the target leakage zone. After a single plugging pulse ends, the plugging slurry is replaced through the external channel and differential identification is re-implemented to determine the mechanical blockage risk and formation plugging effect, and to adjust the injection volume of the next plugging pulse. Grouting is stopped once the target leakage section meets the sealing requirements. The remaining candidate leakage sections are sealed in sequence to complete well cleaning and pressure testing. Normal drilling resumes after the pressure testing is passed.

[0007] Furthermore, the steps for establishing the baseline hydraulic pressure loss models for the inner and outer channels include: A baseline hydraulic pressure loss model for the inner channel, including the pressure loss of the drill bit's waterhole, and a baseline hydraulic pressure loss model for the outer channel, including the pressure loss of the nozzle, are established respectively. Based on the baseline hydraulic pressure loss models, displacement step disturbances are applied to the inner and outer channels respectively to form equal equivalent annular pressure increments and obtain leakage responses. The interval relative leakage index of the well section between the drill bit and the nozzle is calculated, including: keeping the basic displacement of the inner channel constant and applying a displacement step disturbance to the basic displacement of the outer channel; after restoring the basic circulation, keeping the basic displacement of the outer channel constant and applying a displacement step disturbance to the basic displacement of the inner channel; adjusting the amplitude of the two displacement step disturbances to form equal equivalent annular pressure increments at the nozzle depth; substituting the leakage flow increments corresponding to the two disturbances into the interval relative leakage index solution model to calculate the interval relative leakage index of the current identified interval between the nozzle and the drill bit.

[0008] Furthermore, the steps for selecting candidate leakage intervals based on the relative leakage index, testing the equivalent leakage initiation pressure, calculating the blocking priority value, and determining the target leakage interval include: Based on the formation permeability and leakage data of the target block, an anomaly judgment threshold is set, and the identification intervals whose relative leakage index exceeds the anomaly judgment threshold are listed as candidate leakage intervals. The equivalent leakage initiation pressure of the candidate leakage intervals is tested by increasing the equivalent pressure in a preset pressurization step, and the pressure retention coefficient of the candidate leakage intervals is measured after the pump is stopped, the valve is closed and left to stand. The relative leakage index, equivalent leakage initiation pressure and pressure retention coefficient of the candidate leakage intervals are normalized and weighted according to the plugging priority value calculation formula to obtain the plugging priority value. The candidate leakage interval with the largest plugging priority value is determined as the target leakage interval.

[0009] Furthermore, the steps of calculating the lower and upper limits of the allowable injection pressure for the target leakage zone, pulse-injecting plugging slurry into the target leakage zone through the outer channel, and adjusting the drilling fluid discharge rate synchronously injected through the inner channel based on the annular flow velocity of the target leakage zone include: The sum of the equivalent leakage initiation pressure and the injection pressure margin of the target leakage zone is determined as the lower limit of the allowable injection pressure. The pressure increment of the estimated formation fracture pressure at the nozzle depth relative to the annular pressure under the basic circulation state, minus the safety margin, is determined as the upper limit of the allowable injection pressure, thus defining the effective safe injection window. The single injection volume is set to 30% to 50% of the effective injectable volume of the target leakage zone. Within the effective safe injection window formed by the lower and upper limits of the allowable injection pressure, the plugging slurry is pulsed and injected through the external channel. The annular flow velocity of the target leakage zone is controlled between the gravity settling velocity of the plugging slurry solid particles and the critical flow velocity for erosion resistance of the sealing structure. The target matching displacement of the internal channel is calculated, and the top drive system is fed back to adjust the drilling fluid displacement injected synchronously into the internal channel.

[0010] Furthermore, after a single plugging pulse ends, the steps of replacing the plugging slurry through the external channel and re-implementing differential identification to determine the mechanical blockage risk and formation plugging effect, and adjusting the injection volume of the next plugging pulse, include: After the pressure holding time or initial setting strength conditions are met according to the type of plugging slurry, the real-time relative leakage index of the interval is re-measured using differential identification to determine the effective plugging status of the target leakage interval. When the pressure at the inlet of the outer channel increases, and the real-time relative leakage index of the interval does not decrease and the wellhead return flow does not increase, it is determined that there is a risk of mechanical blockage, and clean drilling fluid is pumped into the outer channel for forward flushing. The plugging qualification threshold is set according to the allowable leakage of the drilling project and the maximum fluctuation of the interval relative leakage index. When the real-time relative leakage index of the interval is higher than the plugging qualification threshold, the set injection volume of the next plugging pulse is calculated according to the ratio of the currently measured real-time relative leakage index of the interval to the interval relative leakage index before the first plugging pulse.

[0011] Furthermore, once the target leakage section meets the sealing requirements, grouting is stopped, and the remaining candidate leakage sections are sealed sequentially to complete well cleaning and pressure testing. Normal drilling resumes only after the pressure testing is successful. The steps include: Based on the allowable leakage in drilling engineering, a sealing qualification threshold is set. When the real-time relative leakage index of the target leakage interval is lower than the sealing qualification threshold, pulse grouting of the target leakage interval is stopped, and the target leakage interval is removed from the candidate leakage interval set. Differential identification is re-implemented for the remaining candidate leakage intervals, the sealing priority value is updated, and they are sealed sequentially. After all candidate leakage intervals are sealed, the dual-channel connector is switched back to single-injection dual-channel working state, and the circulation flow rate is increased in stages to conduct a full-section pressure-bearing capacity verification test. When the wellhead return flow rate is not lower than the flow rate after deducting the allowable leakage in drilling engineering design from the conventional circulation injection flow rate, the wellbore leakage is not greater than the allowable leakage in drilling engineering design, and the equivalent pressure-bearing coefficient of the entire well section is not lower than the qualified lower limit, the pressure-bearing verification is deemed qualified and continuous drilling is resumed.

[0012] The second aspect of this invention provides a wellbore multi-layer complex leakage dual-channel adaptive plugging device for drilling, using the wellbore multi-layer complex leakage dual-channel adaptive plugging method for drilling provided in the first aspect. The device includes: The device consists of a dual-channel connector, at least one dual-channel drill pipe, a bypass sub, and a lower drill string assembly, connected sequentially from top to bottom. The dual-channel connector has a central tube inside, and the dual-channel drill pipe has an inner tube coaxially arranged inside, forming a continuously physically isolated inner and outer channel within the device. The dual-channel connector has both single-injection dual-channel and double-injection dual-channel operating modes. The bypass sub has a nozzle on its side, and the inner channel extends downward along the center of the sub's interior, connecting sequentially with the internal flow channel of the lower drill string assembly. The outer channel connects to the nozzle inside the bypass sub.

[0013] Furthermore, the dual-channel connector includes an outer tube body, an upper connector body, a central tube, an inner tube column with a male thread at the lower end, a connector connecting flange, a sealing sleeve, an outer channel injection valve, an outer channel injection pipe, and a union; the internal space of the central tube and the inner tube column connected to the lower end of the central tube together form an inner channel; the annular space between the outer wall of the central tube and the inner wall of the outer tube body, and the annular space between the outer wall of the inner tube column and the inner wall of the outer tube body are continuously connected and together form an outer channel; A bypass hole is provided on the side wall of the central tube; a sealing sleeve is fixedly installed at the upper end of the inner tube column and located inside the outer tube body, and the sealing sleeve is sleeved on the outer circumference of the central tube; a joint connecting flange is fixedly installed between the inner tube column with the male thread of the joint inner tube at the lower end and the outer tube body, and a joint flange flow hole is provided on the joint connecting flange; an outer channel injection pipe communicating with the outer channel is provided on the side of the outer tube body. An external channel injection valve is installed on the external channel injection pipe; a union is connected to the outer end of the external channel injection pipe; an upper connector female thread is provided at the upper end of the upper connector body, and the upper connector male thread at the lower end of the upper connector body engages with the female thread of the outer tube body on the outer tube body; the central tube is connected to the upper connector body; when the upper connector body moves axially relative to the outer tube body, it drives the central tube to slide axially relative to the outer tube body and the inner tube column with the male thread of the inner tube at the lower end of the connector; the bypass hole of the central tube enters the sealing range of the sealing rubber sleeve; the lower end of the dual-channel connector is provided with the male thread of the inner tube and the male thread of the outer tube; a connector sealing ring is provided at the sealing connection position of the dual-channel connector.

[0014] Furthermore, the dual-channel drill pipe includes an outer drill pipe, an inner drill pipe, and a connecting flange; the inner drill pipe is coaxially disposed inside the outer drill pipe; the connecting flange is fixedly connected to both the outer and inner drill pipes; the connecting flange has a flow hole for communicating with the outer channel; two adjacent dual-channel drill pipes are connected by the male thread of the inner drill pipe and the female thread of the inner drill pipe, and by the male thread of the outer drill pipe and the female thread of the outer drill pipe; a sealing ring is provided at the connection position of two adjacent dual-channel drill pipes; the lower end of the dual-channel drill pipe has a male thread of the inner drill pipe and a male thread of the outer drill pipe; the upper end of the dual-channel drill pipe has a female thread of the inner drill pipe and a female thread of the outer drill pipe.

[0015] Furthermore, the bypass sub includes a sub body; the outer female thread of the sub at the upper end of the sub body is sealed to the male thread of the drill pipe outer tube of the dual-channel drill pipe; the inner female thread of the sub at the upper end of the sub body is sealed to the male thread of the drill pipe inner tube of the dual-channel drill pipe; a sub sealing ring is provided at the connection position between the dual-channel drill pipe and the bypass sub; the male thread of the lower end of the sub at the lower end of the sub body is connected to the female thread of the upper end of the lower drill tool assembly; a bypass flow channel communicating with the outer channel is provided inside the sub body, and the bypass flow channel is connected to the nozzle located on the side of the sub body.

[0016] This invention provides a dual-channel adaptive plugging device and method for complex multi-layered leakage in wellbores. It possesses the following beneficial technical effects: 1. This invention sets a central tube and an inner tube inside the dual-channel joint and the dual-channel drill pipe to form physically isolated inner and outer channels. By manipulating the upper joint body to move axially relative to the outer tube body, the central tube is driven to slide axially and the central tube bypass hole opened on the side wall of the central tube enters the coverage and sealing range of the sealing rubber sleeve, switching the dual-channel joint from single injection dual-channel working state to double injection dual-channel working state. This avoids the process of pulling out the dual-channel drill string assembly and running in a special plugging string, shortening the leakage handling time.

[0017] 2. When locating the leakage interval, this invention applies a step disturbance to the outer channel while keeping the basic discharge rate of the inner channel constant, and applies a step disturbance to the inner channel while keeping the basic discharge rate of the outer channel constant. The amplitude of the two step disturbances is adjusted so that the two step disturbances form an equal equivalent annular pressure increment at the nozzle depth. The leakage flow increment corresponding to the two step disturbances is substituted into the interval relative leakage index calculation model to calculate the interval relative leakage index of the identified interval between the nozzle and the drill bit. This eliminates the interference of background leakage in the well section above the nozzle and realizes the quantitative identification of the relative leakage degree of a specific leakage interval.

[0018] 3. In the grouting stage, this invention pulses the plugging slurry into the target leakage zone through the external channel, while simultaneously injecting drilling fluid through the internal channel. The flow rate of the drilling fluid injected into the internal channel is adjusted according to the annular flow velocity of the target leakage zone, so as to control the annular flow velocity of the target leakage zone between the gravity settling velocity of the plugging slurry solid particles and the critical flow velocity of the sealing structure against erosion. This avoids mechanical blockage of the external channel, bypass flow channel or nozzle caused by the settling of the plugging slurry solid particles, and at the same time avoids the wellbore fluid from eroding and damaging the pressure-bearing sealing structure of the target leakage zone. Attached Figure Description

[0019] Figure 1 This is a perspective view of the present invention; Figure 2 This is a schematic diagram of the male thread of the connector inner tube of the present invention; Figure 3 This is a schematic diagram of the male thread of the drill pipe inner tube according to the present invention; Figure 4 This is a schematic diagram of the external female thread of the short section of the present invention; Figure 5 This is a schematic diagram of the method flow of the present invention; Figure 6 A timeline diagram was established for the baseline hydraulic pressure loss model of this invention; Figure 7 This is a timing diagram of the leakage interval identification and target leakage interval determination of the present invention; Figure 8 This is a schematic diagram of the dual-channel synchronous grouting and target matching displacement feedback control principle of the present invention; Figure 9 This is a flowchart of the test procedure for updating candidate leakage intervals and verifying the pressure-bearing capacity of the entire well section in this invention. Figure 10 Figure 1 shows the simulation results of the wellbore multi-layer complex leakage dual-channel adaptive plugging system during drilling according to the present invention. Figure 2 shows the dynamic grouting and annular pressure spatial evolution characteristics, Figure 3 shows the decay curve of the relative leakage index of the candidate interval as the plugging process progresses, Figure 4 shows the comparison of the discharge and return volume of the pressure-bearing capacity verification test of the whole well section, and Figure 5 shows the dynamic balance response of the circulating pool liquid level height in the early stage of drilling.

[0020] The components include: 1. Dual-channel connector; 2. Dual-channel drill pipe; 3. Bypass sub; 4. Drill collar; 5. Screw drill bit; 6. Drill bit; 101. Male thread on the inner tube of the connector; 102. Male thread on the outer tube of the connector; 103. Connecting flange of the connector; 104. Flow hole on the flange of the connector; 105. Sealing sleeve; 106. Bypass hole of the central tube; 107. Central tube; 108. Female thread on the outer tube body; 109. Outer tube body; 110. Male thread on the upper connector; 111. Upper connector body; 112. Female thread on the upper connector; 113. External channel injection valve; 114. External channel injection pipe; 115. Union. Head; 116, Joint sealing ring; 117, Outer channel; 118, Inner channel; 201, Male thread of drill pipe inner tube; 202, Male thread of drill pipe outer tube; 203, Drill pipe connecting flange; 204, Drill pipe flange flow hole; 205, Drill pipe outer tube; 206, Drill pipe inner tube; 207, Female thread of drill pipe inner tube; 208, Female thread of drill pipe outer tube; 209, Drill pipe sealing ring; 301, Male thread of lower end of short section; 302, Short section body; 303, Nozzle; 304, Bypass flow channel; 305, Female thread of outer layer of short section; 306, Female thread of inner layer of short section; 307, Short section sealing ring. Detailed Implementation

[0021] The specific embodiments of the present invention will be further described in detail below with reference to the accompanying drawings and examples.

[0022] See attached document Figures 1 to 4 The present invention provides a wellbore multi-layer complex leakage dual-channel adaptive plugging device, the device comprising: The lower drilling assembly consists of a double-channel connector 1, at least one double-channel drill pipe 2, a bypass sub 3, a drill collar 4, a screw drill tool 5, and a drill bit 6, connected sequentially from top to bottom. The drill collar 4, the screw drill tool 5, and the drill bit 6 together constitute the lower drilling tool assembly.

[0023] The dual-channel connector 1 includes an outer tube body 109, an upper connector body 111, a central tube 107, an inner tube column with a male thread 101 at its lower end, a connector connecting flange 103, a sealing sleeve 105, an outer channel injection valve 113, an outer channel injection pipe 114, and a union 115; the internal space of the central tube 107 and the inner tube column connected to the lower end of the central tube 107 together form an inner channel 118; the annular space between the outer wall of the central tube 107 and the inner wall of the outer tube body 109 is used to... The annular space between the outer wall of the inner tube column and the inner wall of the outer tube body 109 is continuously connected and together forms the outer channel 117; the lower end of the central tube 107 can slide axially into the interior of the inner tube column, and the sealing sleeve 105 forms a sliding seal between the central tube 107 and the inner tube column; a joint sealing ring 116 is provided at the sealing connection position of the dual-channel joint 1, and the joint sealing ring 116 restricts the fluid from flowing through the predetermined flow path of the inner channel 118 and the outer channel 117 or leaking to the external environment.

[0024] The lower end of the dual-channel connector 1 is provided with a male thread 101 for the inner tube and a male thread 102 for the outer tube, which are respectively sealed and connected to the female thread 207 for the inner tube and the female thread 208 for the outer tube of the uppermost dual-channel drill rod 2; the connector connecting flange 103 is fixedly installed between the inner tube column with the male thread 101 for the inner tube at the lower end and the outer tube body 109; the lower end of the central tube 107 can slide axially into the inner tube column from above the connector connecting flange 103; the connector connecting flange 103 is provided with a connector flange flow hole 104; the connector flange flow hole 104 ensures that the outer channel 117 remains axially continuous at the location of the connector connecting flange 103.

[0025] The upper connector body 111 has an upper connector female thread 112 at its upper end, which connects to the top drive or square drill pipe; the upper connector male thread 110 at the lower end of the upper connector body 111 engages with the outer tube body female thread 108 on the outer tube body 109; the central tube 107 is connected to the upper connector body 111; when the upper connector body 111 moves axially relative to the outer tube body 109, it drives the central tube 107 to slide axially relative to the outer tube body 109 and the inner tube column with the connector inner tube male thread 101 at its lower end; the sealing rubber sleeve 105 is fixedly installed at the upper end of the inner tube column and located inside the outer tube body 109, and the sealing rubber sleeve 105 is sleeved on the outer circumference of the central tube 107; the outer tube body 109 has an outer channel injection pipe 114 on its side that communicates with the outer channel 117; an outer channel injection valve 113 is installed on the outer channel injection pipe 114; and a union joint 115 is connected to the outer end of the outer channel injection pipe 114.

[0026] The dual-channel connector 1 has a single-injection dual-channel working state and a double-injection dual-channel working state. In the single-injection dual-channel working state corresponding to conventional drilling, the central tube bypass hole 106 is outside the sealing range of the sealing sleeve 105. The inner channel 118 is connected to the outer channel 117 through the central tube bypass hole 106. The outer channel injection valve 113 is kept closed. The drilling fluid injected by the top drive or angular drill pipe enters the inner channel 118 and the outer channel 117 respectively and forms a conventional circulation. The flow capacity of the central tube bypass hole 106, the nozzle 303 and the water eye of the drill bit 6 are matched with each other. The drilling fluid discharge rate entering the inner channel 118 is not less than the minimum working discharge rate of the screw drill string 5.

[0027] When the upper connector body 111 is rotated and the male thread 110 of the upper connector is further screwed into the female thread 108 of the outer tube body, the upper connector body 111 drives the central tube 107 to slide axially downward relative to the outer tube body 109 and the inner tube column with the male thread 101 of the inner tube at the lower end; the bypass hole 106 of the central tube enters the sealing range covered by the sealing sleeve 105; the sealing sleeve 105 makes sealing contact with the outer wall of the central tube 107 on the axial upper side and axial lower side of the bypass hole 106 of the central tube, respectively, and the outer channel 117 between the outer wall of the inner tube column and the inner wall of the outer tube body 109 remains axially connected; the inner channel 118 is isolated from the outer channel 117, and the dual-channel connector 1 switches to the dual-injection dual-channel working state; after the outer channel injection valve 113 is opened, the fluid injected by the top drive or square drill pipe enters the inner channel 118 independently. The ground pump unit injects fluid independently into the outer channel 117 via the union 115 and the outer channel injection pipe 114; the inner channel 118 and the outer channel 117 form independent injection paths respectively; while the ground pipeline remains connected to the union 115, the dual-channel drill assembly stops rotating and the outer pipe body 109 remains fixed; after closing the outer channel injection valve 113, releasing the pressure in the outer channel injection pipe 114, and disconnecting the union 115 from the ground pipeline, the dual-channel drill assembly resumes rotation.

[0028] The dual-channel drill pipe 2 includes an outer drill pipe 205, an inner drill pipe 206, and a drill pipe connecting flange 203; the outer drill pipe 205 bears and transmits rotational torque, drilling pressure, and axial tensile load; the inner drill pipe 206 is coaxially disposed inside the outer drill pipe 205; the internal space of the inner drill pipe 206 forms an inner channel 118, and the inner drill pipe 206 bears the fluid pressure in the inner channel 118; the annular space between the outer drill pipe 205 and the inner drill pipe 206 forms an outer channel 117.

[0029] The drill pipe connecting flange 203 is fixedly connected to the drill pipe outer tube 205 and the drill pipe inner tube 206 respectively, and maintains the coaxial relationship between the drill pipe outer tube 205 and the drill pipe inner tube 206; the drill pipe connecting flange 203 is provided with a drill pipe flange flow hole 204; the drill pipe flange flow hole 204 ensures that the outer channel 117 remains continuously open at the location of the drill pipe connecting flange 203.

[0030] The lower end of the dual-channel drill pipe 2 is provided with a male thread 201 for the inner tube and a male thread 202 for the outer tube; the upper end of the dual-channel drill pipe 2 is provided with a female thread 207 for the inner tube and a female thread 208 for the outer tube; two adjacent dual-channel drill pipes 2 are connected by screwing the male thread 201 and the female thread 207 for the inner tube, and by screwing the male thread 202 and the female thread 208 for the outer tube; a drill pipe sealing ring 209 is provided at the connection position of two adjacent dual-channel drill pipes 2, and the inner thread connection, the outer thread connection and the drill pipe sealing ring 209 together constitute a sealing and load-bearing structure; the inner channel 118, the outer channel 117 and the wellbore annulus 3 are physically isolated; no independent sealing joint is provided between two adjacent dual-channel drill pipes 2.

[0031] The bypass sub 3 includes a sub body 302; the outer female thread 305 of the sub body 302 at the upper end of the sub body 302 is sealed to the drill pipe outer tube male thread 202 of the dual-channel drill pipe 2; the inner female thread 306 of the sub body 302 at the upper end of the sub body is sealed to the drill pipe inner tube male thread 201 of the dual-channel drill pipe 2; a sub sealing ring 307 is provided at the connection position between the dual-channel drill pipe 2 and the bypass sub 3, and the sub sealing ring 307 isolates the inner channel 118, the outer channel 117 and the wellbore annulus from each other; the lower male thread 301 of the sub body 302 at the lower end of the sub body is connected to the upper female thread of the drill collar 4; the lower end of the drill collar 4 is connected in sequence to the screw drill tool 5 and the drill bit 6.

[0032] The sub-body 302 has a bypass flow channel 304 connected to the outer channel 117. The bypass flow channel 304 is connected to the nozzle 303 located on the side of the sub-body 302. The fluid or plugging slurry in the outer channel 117 flows through the bypass flow channel 304 and the nozzle 303 in sequence, and is discharged into the wellbore annulus from the side of the sub-body 302. The fluid in the outer channel 117 forms an annulus hydraulic disturbance in the well section above the nozzle 303, and the plugging slurry enters the target leakage zone from the side of the nozzle 303. The inner channel 118 extends downward along the center of the sub-body 302 and is connected to the internal flow channels of the drill collar 4, the screw drill 5 and the drill bit 6 in sequence. The fluid in the inner channel 118 is discharged into the bottom annulus from the drill bit 6, forming a bottom annulus hydraulic disturbance and regulating the annulus flow velocity in the target leakage zone.

[0033] See attached document Figure 5 The present invention provides a method for adaptive plugging of complex multi-layer leakage in wellbores through dual channels while drilling, the method comprising the following steps: S1. Connect the dual-channel connector 1, at least one dual-channel drill pipe 2, bypass sub 3, drill collar 4, screw drill string 5, and drill bit 6 in sequence and lower them to the well section without leakage; switch the dual-channel connector 1 to the dual-injection dual-channel working state; inject drilling fluid into the inner channel 118 and the outer channel 117 respectively; establish the inner channel reference hydraulic pressure loss model including the water hole pressure loss of drill bit 6 and the outer channel reference hydraulic pressure loss model including the pressure loss of nozzle 303 respectively.

[0034] S2. Move the bypass sub 3 to the section of the well to be identified for leakage, so that both the nozzle 303 and the drill bit 6 are located within the section of the well to be identified for leakage, and determine the section between the depth of the nozzle 303 and the depth of the drill bit 6 as the current identification interval; apply displacement step disturbances to the inner channel 118 and the outer channel 117 respectively; adjust the amplitude of the two displacement step disturbances until the two disturbances form equal equivalent annular pressure increments at the depth of the nozzle 303; calculate the interval relative leakage index of the section between the drill bit 6 and the nozzle 303 based on the leakage response corresponding to the two disturbances.

[0035] S3. Identify intervals whose relative leakage index exceeds the anomaly judgment threshold as candidate leakage intervals; test the equivalent leakage initiation pressure of the candidate leakage intervals; calculate the pressure retention coefficient and blocking priority value of the candidate leakage intervals; determine the target leakage interval according to the blocking priority value; calculate the lower limit and upper limit of the allowable injection pressure of the target leakage interval.

[0036] S4. Move the bypass section 3 to the target leakage zone so that the nozzle 303 is within the target leakage zone; inject the plugging slurry into the target leakage zone through the outer channel 117 via the bypass flow channel 304 and the nozzle 303; inject drilling fluid simultaneously through the inner channel 118 and adjust the annular flow rate of the target leakage zone.

[0037] S5. After a single plugging pulse ends, drilling fluid is injected through the outer channel 117; the plugging slurry in the outer channel 117 and the bypass flow channel 304 is replaced to the target leakage zone; after the pressure holding time or initial setting strength condition is met according to the plugging slurry type, differential identification is re-implemented based on the change in the relative leakage index of the zone and the change in the hydraulic resistance of the inner channel 118 and the outer channel 117 to determine the mechanical blockage risk and formation plugging effect; the injection volume of the next plugging pulse is adjusted according to the determination result.

[0038] S6. Grouting is stopped after the target leakage section meets the sealing requirements; the dual-channel drill string assembly is moved; differential identification is re-implemented for the remaining candidate leakage sections and the sealing priority value is updated; the remaining candidate leakage sections are sealed sequentially according to the updated sealing priority value; after all target leakage sections are sealed, the dual-channel drill string assembly is lifted; the dual-channel drill string assembly and wellbore annulus are flushed through inner channel 118 and outer channel 117; the grout is allowed to stand or wait for solidification according to the type of plugging grout; well cleaning and pressure testing are completed; normal drilling is resumed after the pressure testing is qualified; if the pressure testing is unqualified, the process returns to S2 for re-identification.

[0039] See attached document Figure 6 In specific implementations, step S1 provided by the present invention may include the following steps: S11. Connect the dual-channel connector 1, at least one dual-channel drill pipe 2, bypass short section 3, drill collar 4, screw drill string 5, and drill bit 6 sequentially from top to bottom with threads to form a dual-channel drill string assembly with continuous internal flow channels; lower the dual-channel drill string assembly into the wellbore using the drilling rig hoisting equipment; calculate the wellbore formation leakage per unit time based on the drilling fluid level consumption records during the previous drilling process, and determine the well section to be calibrated based on the sonic logging curves fed back by the logging-while-drilling system; When the formation leakage per unit time in the wellbore is less than 0.2m 3 At a rate of / h, confirm that the depth positions of drill bit 6 and nozzle 303 are both in the no-leakage section and stop lowering; conduct multiple stable cycle tests in the no-leakage section, and determine the allowable error of the benchmark calibration based on the maximum fluctuation of the difference between the injected flow rate and the wellhead return flow rate in each test, the drilling fluid level measurement error, and the flow rate measurement error; the injected drilling fluid returns upward to the surface through the wellbore annulus; when the flow rate deviation caused by formation absorption does not exceed the allowable error of the benchmark calibration, use the pressure and flow rate data of the corresponding well section to calibrate the pipeline hydraulic parameters.

[0040] S12. The control device switches from single-injection dual-channel operation to dual-injection dual-channel operation; stops the pumping operation of the ground pump group and the top drive system; opens the throttle valve to release the residual pressure in the internal pipeline; keeps the outer pipe body 109 and the lower pipe column connected to the outer pipe body 109 from rotating; controls the top drive to drive the upper connector body 111 to rotate relative to the outer pipe body 109 along the tightening direction of the upper connector male thread 110; the upper connector male thread 110 set at the lower end of the upper connector body 111 is screwed into the outer pipe body female thread 108 machined on the inner wall of the outer pipe body 109; the rotation of the upper connector body 111 is converted into axial downward movement through the thread pair; the upper connector body 111 pushes the central pipe 107 to slide downward along the central axis relative to the outer pipe body 109 and the inner pipe column with the lower end set with the connector inner pipe male thread 101. The bypass hole 106 of the central tube enters the sealing range covered by the sealing sleeve 105; the sealing sleeve 105 makes sealing contact with the outer wall of the central tube 107 on the axial upper and axial lower sides of the bypass hole 106 of the central tube respectively; the bypass hole 106 of the central tube is closed by the sealing sleeve 105; the fluid exchange path between the inner channel 118 and the outer channel 117 is blocked, and the inner channel 118 and the outer channel 117 form a hydraulic isolation; the outer channel injection valve 113 is kept closed, the outlet pipeline of the ground pump set is connected to the union 115, and after the connection is completed, the outer channel injection valve 113 is opened to connect the injection path between the outer channel 117 and the ground pump set.

[0041] S13. Drilling fluid is injected independently into the inner channel 118 and the outer channel 117 to establish the inner channel circulation flow field and the outer channel circulation flow field respectively; the dual-channel drill string assembly is kept stationary; the top drive continuously pumps drilling fluid into the inner channel 118 through the square drill pipe joint or the top drive joint; the surface pump set continuously pumps drilling fluid into the outer channel 117 through the union joint 115 and the outer channel injection pipe 114; the drilling fluid entering the inner channel 118 flows sequentially through the drill pipe inner tube 206 and the extension of the inner channel 118 within the short section body 302. The drill fluid, consisting of the extension section, drill collar 4, and screw drill string 5, is discharged into the bottom annulus of the wellbore through the water hole at the end of the drill bit 6. The drilling fluid entering the outer channel 117 flows downward along the annular space, passing sequentially through the gap between the central tube 107 and the outer tube body 109, the joint flange flow hole 104 on the joint connecting flange 103, and the drill pipe flange flow hole 204 on the drill pipe connecting flange 203. The drilling fluid then enters the bypass flow channel 304 and is discharged into the wellbore annulus from the nozzle 303 located on the side wall of the short section body 302.

[0042] The basic displacement of S14 and inner channel 118 is determined based on the minimum working displacement of screw drill string 5, the displacement required for wellbore cleaning, and the allowable displacement of the top drive system; the basic displacement of outer channel 117 is determined based on the allowable displacement of the surface pump set, the flow capacity of nozzle 303, and the stable circulation displacement of the well section without leakage; when calibrating inner channel 118, maintain outer channel 117 at the determined basic displacement and adjust the injection displacement of the top drive; when calibrating outer channel 117, maintain inner channel 118 at the determined basic displacement and adjust the injection displacement of the surface pump set; both inner channel 118 and outer channel 117 have 7 displacement test nodes set in a step interval of 5L / s within the range of 5L / s to 35L / s; The seven displacement test nodes were 5L / s, 10L / s, 15L / s, 20L / s, 25L / s, 30L / s, and 35L / s, respectively. Stable flow was maintained at each displacement test node for 2 to 4 minutes. High-frequency pressure sensors and electromagnetic flowmeters were used to simultaneously collect the inlet pressure of inner channel 118, the injection displacement of inner channel, the inlet pressure of outer channel 117, the injection displacement of outer channel, and the return displacement from the wellhead. The controller calculates the pressure loss of the inner channel 118 and the outer channel 117 based on the collected data, the empirical equation of hydraulic friction along the pipe, the flow coefficient of the drill bit 6 water hole, and the flow coefficient of the nozzle 303. The input parameters of the inner channel reference hydraulic pressure loss model include the injection displacement of the inner channel 118, the drilling fluid density, the drilling fluid rheological parameters, the flow channel size of the inner channel 118, the internal flow channel size of the drill collar 4, the hydraulic pressure loss parameters of the screw drill 5, and the flow coefficient of the drill bit 6 water hole. The output parameter is the reference hydraulic pressure loss between the inlet of the inner channel 118 and the outlet of the drill bit 6. The input parameters of the outer channel reference hydraulic pressure loss model include the injection displacement of the outer channel 117, the drilling fluid density, the drilling fluid rheological parameters, the flow channel size of the outer channel 117, the flow channel size of the bypass flow channel 304, and the flow coefficient of the nozzle 303. The output parameter is the reference hydraulic pressure loss between the inlet of the outer channel 117 and the outlet of the nozzle 303. The friction coefficient and flow index along the path are solved by fitting using the nonlinear least squares method; the flow coefficients of the drill bit 6 water hole and the nozzle 303 are determined based on the structural design parameters, the results of surface flow tests, or the calibration results of the well section without leakage; when the fitting residual and the variation of the parameter to be fitted do not exceed the allowable range corresponding to the repeated measurement error of the data acquisition system, the fitting calculation is considered to have converged; if the fitting calculation has not converged, the initial step size is adjusted and the iteration is repeated; based on the converged fitting results, the reference hydraulic pressure loss model of the inner channel and the reference hydraulic pressure loss model of the outer channel are established respectively.

[0043] See attached document Figure 7 In specific implementations, steps S2 and S3 provided by this invention may include the following steps: S21. Based on the geological logging data and the real-time transmission trend of the equivalent circulating density at the bottom of the well via the measurement-while-drilling system, determine the depth range of the lost well section to be identified; by axially moving the dual-channel drill string assembly through the drilling rig hoisting equipment, lower or raise the bypass sub 3 to the lost well section to be identified; ensure that both the nozzle 303 and the drill bit 6 are located within the lost well section to be identified, and determine the section between the depth of the nozzle 303 and the depth of the drill bit 6 as the current identification interval; keep the dual-channel connector 1 in a dual-injection, dual-channel working state; The surface pump unit and top drive system inject drilling fluid into the outer channel 117 and inner channel 118 respectively according to the basic discharge rates of the outer channel 117 and inner channel 118 determined in S14. When the changes in the inlet pressure of the inner channel 118, the inlet pressure of the outer channel 117, and the return discharge rate at the wellhead all do not exceed the allowable fluctuation range corresponding to the repeated calibration results in S14, the basic circulation is determined to have reached a stable state, and the inlet pressure of the inner channel 118, the injection discharge rate of the inner channel, the inlet pressure of the outer channel 117, the injection discharge rate of the outer channel, and the return discharge rate at the wellhead are recorded as differential identification reference baselines.

[0044] S22. While keeping the basic discharge rate of the inner channel 118 unchanged, apply an independent discharge rate step disturbance to the outer channel 117; control the surface pump group to increase the injection discharge rate of the outer channel 117 to the sum of the basic discharge rate and the preset outer channel disturbance increment; the outer channel disturbance increment is 10% to 20% of the basic discharge rate; the drilling fluid is discharged through the bypass flow channel 304 and nozzle 303, causing a change in the wellbore annular pressure; Real-time acquisition of inlet pressure changes in external channel 117; calling the external channel reference hydraulic pressure loss model established in S1; deducting the frictional increase along the path and the throttling pressure drop increase of nozzle 303 corresponding to the external channel disturbance increment; calculating the equivalent annular pressure increment at the depth of nozzle 303; after confirming that the flow field has reached a stable state according to the stable state judgment conditions recorded in S21, recording the injection discharge increment of external channel 117 and the wellhead return discharge increment after wellbore fluid transmission time correction; The wellbore fluid transfer time is calculated based on the effective volume of the wellbore annulus between nozzle 303 and the wellhead and the basic circulation return discharge rate, or determined based on the time difference between the start time of the discharge disturbance in the outer channel 117 and the start time of the return discharge rate response at the wellhead; the injection discharge rate of the outer channel 117 is restored to the basic discharge rate; after the inlet pressure of the inner channel 118, the inlet pressure of the outer channel 117, and the return discharge rate at the wellhead are all restored to the allowable fluctuation range of the stable value before the disturbance of the outer channel 117, the step disturbance of the discharge rate of the inner channel 118 is then performed; the allowable fluctuation range is determined based on the maximum fluctuation of the pressure and return discharge rate obtained by repeated calibration under the same discharge rate conditions in S14.

[0045] S23. While keeping the basic displacement of the outer channel 117 constant, apply an independent displacement step disturbance to the inner channel 118; control the top drive system to increase the injection displacement of the inner channel 118 from the basic displacement to the target disturbance displacement, and control the rate of change during the displacement switching process to 0.5 L / s. 2 Up to 1L / s 2 After reaching the target disturbance discharge rate, the injection discharge rate of the inner channel 118 is kept stable; the inlet pressure data of the inner channel 118 is collected in real time; the reference hydraulic pressure loss model of the inner channel established by S1 is called; the frictional resistance increment generated by the drilling fluid flowing through the drill pipe inner tube 206 and the local pressure drop increment generated by the water hole of the drill bit 6 are deducted; the annular pressure increment at the depth of the drill bit 6 is calculated. Based on the annular pressure loss between the depth of drill bit 6 and the depth of nozzle 303, the annular pressure increment at the depth of drill bit 6 is converted into the equivalent annular pressure increment at the depth of nozzle 303; by adjusting the injection displacement of inner channel 118 through feedback, the equivalent annular pressure increment formed by the disturbance of inner channel 118 and the disturbance of outer channel 117 at the depth of nozzle 303 is equal. When the injection displacement of the inner channel 118 required for equivalent annular pressure increment matching exceeds the top drive pumping capacity, the disturbance increment of the outer channel 117 is reduced, and the disturbance of the outer channel 117 and the disturbance of the inner channel 118 are re-executed; if equivalent annular pressure increment matching still cannot be achieved within the allowable displacement range of the equipment, the corresponding data is not used to calculate the interval relative leakage index; after completing effective equivalent annular pressure increment matching, the flow field is confirmed to have reached a stable state according to the stable state judgment conditions recorded in S21, and the injection displacement increment of the inner channel 118 and the wellhead return displacement increment after wellbore fluid transmission time correction are recorded.

[0046] S24, nozzle 303, and drill bit 6 sequentially apply equal equivalent pressure excitation within the wellbore annulus; the difference in leakage response corresponding to the two pressure excitations weakens the background leakage influence of the shared well section above nozzle 303 and characterizes the leakage response of the current identification interval between nozzle 303 and drill bit 6; the leakage flow increment is substituted into the interval relative leakage index solution model; the interval relative leakage index is calculated according to the following formula: ; In the formula, This is the interval relative leakage index; The change in displacement injected into the inner channel under disturbance conditions; The change in the total wellhead return discharge rate after wellbore fluid transmission time correction relative to the stable value before the inner channel 118 disturbance when implementing the step disturbance of the discharge rate in the inner channel 118. The change in displacement is injected into the outer channel under disturbance conditions; The change in the total wellhead return discharge rate after wellbore fluid transmission time correction relative to the stable value before the external channel 117 disturbance when implementing a step disturbance of the discharge rate of the external channel 117. The equivalent annular pressure increment formed by the disturbances in the inner channel 118 and the outer channel 117 at the depth of the nozzle 303 is matched; the disturbances in the inner channel 118 and the outer channel 117 use data acquisition windows of the same length; when the matching error of the equivalent annular pressure increment exceeds the allowable range corresponding to the repeatability error of the pressure measurement system, or when the calculated result of the interval relative leakage index is less than 0, the corresponding identification result is marked as invalid, and S22 and S23 are re-executed.

[0047] After completing the test of the current identification range, move the dual-channel drill string assembly along the wellbore axis; the distance between two adjacent movements shall not be greater than the axial distance between nozzle 303 and drill bit 6; when the wellhead return flow rate cannot reach a stable state, use the same length of cumulative fluid loss statistical time window to statistically analyze the cumulative injection volume, wellhead cumulative return volume and drilling fluid tank volume change corresponding to the disturbance of inner channel 118 and outer channel 117 respectively; The cumulative fluid loss statistics time window starts after the displacement disturbance reaches the depth where drill bit 6 or nozzle 303 is located, and the length of the cumulative fluid loss statistics time window is not less than one wellbore fluid transfer time; compare the relative leakage response of the current identification interval based on the cumulative incremental fluid loss; repeat S21 to S24 at the moved drill string position to obtain the interval relative leakage index of adjacent identification intervals.

[0048] S31. Set anomaly judgment threshold; extract the interval relative leakage index obtained by segment calculation in S2, and compare it with the anomaly judgment threshold respectively; the anomaly judgment threshold is determined in the range of 0.15L / (s·MPa) to 0.25L / (s·MPa) based on the formation permeability of the target block, the maximum fluctuation of the interval relative leakage index obtained by repeated identification of the non-leakage well section, and the historical leakage data of the target block. When the relative leakage index of the identified interval is greater than the anomaly judgment threshold, the well section covered by the identified interval is marked as an abnormal leakage well section; the identified intervals that continuously exceed the anomaly judgment threshold and overlap with each other are merged; the depth range of the candidate leakage intervals is determined according to the upper and lower boundaries of the merged identified intervals, and a candidate leakage interval set is established; when the candidate leakage interval set is empty, it is determined that there are no leakage intervals that need to be plugged in the current well section, and the normal drilling cycle is resumed.

[0049] S32. Perform equivalent leakage initiation pressure tests on the candidate leakage intervals in sequence; move the nozzle 303 to each candidate leakage interval by axially moving the dual-channel drill string assembly through the drilling rig hoisting equipment; keep the drilling fluid injected into the inner channel 118 at the basic displacement, and gradually increase the injection displacement of the outer channel 117 through the surface pump set, so that the equivalent annular pressure at the depth of the nozzle 303 increases according to the preset pressure increase step; The pressure increment ranges from 0.3 MPa to 0.8 MPa, preferably 0.5 MPa; the rate of change of the difference between the wellhead return flow and the injection flow is continuously monitored; when the equivalent pressure increment does not reach the leakage channel initiation pressure, the leakage amount changes continuously with the equivalent pressure increment; after the equivalent pressure increment reaches the leakage channel initiation pressure, the growth rate of the incremental leakage amount relative to the previous pressure test node exceeds the allowable deviation jointly determined by the fitting residual of the linear change stage and the repeated test error; When the growth rate of the incremental leakage at two consecutive pressure test nodes relative to their respective preceding pressure test nodes both exceed the allowable deviation jointly determined by the fitting residual and repeated test error of the linear change phase, it is determined that the incremental leakage has shown a continuous nonlinear growth, and the equivalent pressure increment corresponding to the first pressure test node in the two consecutive pressure test nodes is determined as the equivalent leakage initiation pressure of the candidate leakage interval; the equivalent leakage initiation pressure is the equivalent pressure increment of the depth of nozzle 303 relative to the annular pressure under the basic circulation state; the dual-channel drill string combination is moved and the test is repeated until the equivalent leakage initiation pressure test of all candidate leakage intervals in the candidate leakage interval set is completed; After completing the equivalent leakage initiation pressure test, nozzle 303 is held within the corresponding candidate leakage range, and drilling fluid is injected into the inner channel 118 at the basic displacement. The equivalent pressure at the depth of nozzle 303 is increased to the holding pressure and kept stable through the outer channel 117. The holding pressure is lower than the pressure increment of the estimated formation fracture pressure at the depth of nozzle 303 relative to the annular pressure under the basic circulation state, and the same holding pressure increment is used for all candidate leakage ranges. Close the external channel injection valve 113 and record the initial pressure increment when the external channel injection valve 113 is closed and the remaining pressure increment after the holding time. The holding time is determined based on the shortest test time that the pressure decay curve can form a continuous and stable trend, and the same holding time is used for all candidate leakage intervals. The ratio of the remaining pressure increment to the initial pressure increment is determined as the pressure holding coefficient.

[0050] S33. Determine the blocking priority value of the candidate leakage interval based on the interval relative leakage index, pressure maintenance coefficient, and equivalent leakage initiation pressure; normalize the interval relative leakage index, pressure maintenance coefficient, and equivalent leakage initiation pressure, and then perform weighted calculations based on the leakage index weighting coefficient, pressure release index weighting coefficient, and initiation pressure weighting coefficient respectively: ; In the formula, The priority value for blocking; The leakage index weighting coefficient is used in this embodiment. The value ranges from 0.4 to 0.6, preferably 0.5; This is the interval relative leakage index for the current candidate leakage interval; The maximum interval relative leakage index in the candidate leakage interval set; In this embodiment, the weighting coefficient for the pressure release index is... The value ranges from 0.2 to 0.4, preferably 0.3; This is the pressure retention coefficient. The ratio of the remaining pressure increment after the holding time determined by S32 after closing the external channel injection valve 113 to the initial pressure increment when the external channel injection valve 113 is closed. The value range is from 0 to 1. The larger the value, the stronger the pressure retention capability of the candidate leakage interval; This indicates the relative degree of pressure release within the candidate leakage interval; In this embodiment, the pressure weighting coefficient is activated. The value ranges from 0.1 to 0.3, preferably 0.2; Equivalent leakage starting pressure; This represents the pressure increment of the estimated formation fracturing pressure at the depth of nozzle 303 relative to the annular pressure under the basic circulation state.

[0051] and All values ​​used are equivalent pressure values ​​at the depth of nozzle 303 and under the same pressure reference. , and All are non-negative numbers, and , and The sum equals 1; , and Based on the historical leakage data of the target block and the leakage response of the candidate leakage interval, if the historical leakage data of the target block cannot be obtained, the following method is adopted: 0.5 0.3 It is 0.2; Determined based on formation pressure test, leakage test, or data from adjacent wells in the same formation; When the value is 0, the blocking priority value is not calculated, and the relative leakage index of the candidate leakage interval is returned to S2 for verification.

[0052] S34. Sort the candidate leakage intervals from largest to smallest according to the sealing priority value, and determine the candidate leakage interval with the largest sealing priority value as the target leakage interval; determine the sum of the equivalent leakage initiation pressure and the injection pressure margin of the target leakage interval as the lower limit of the allowable injection pressure; the injection pressure margin is determined based on the repeated measurement error of the pressure measurement system, the pressure increment when the plugging slurry begins to continuously enter the leakage channel during the historical plugging construction of the target block, and the rheological parameters of the plugging slurry; When historical plugging construction data for the target block cannot be obtained, the injection pressure margin is determined based on the ground injection test results of the plugging grout with the same formula; the pressure increment after deducting the safety margin from the pressure increment of the estimated formation fracture pressure at the depth of nozzle 303 relative to the annular pressure under the foundation circulation state is determined as the upper limit of the allowable injection pressure; the safety margin ranges from 1.5MPa to 3MPa, preferably 2MPa. Both the lower and upper limits of the allowable injection pressure are expressed using the equivalent pressure at the depth of nozzle 303. The pressure of the surface pumping manifold is converted into the squeezing pressure at the depth of nozzle 303 using the external channel reference hydraulic pressure loss model, and the squeezing pressure is controlled between the lower and upper limits of the allowable injection pressure. When the lower limit of the allowable injection pressure is greater than or equal to the upper limit of the allowable injection pressure, the target leakage interval is marked as an interval without an effective safe injection window, and pressurization and squeezing into the target leakage interval are stopped. Intervals without an effective safe injection window are excluded from the current plugging sequence. When there are other untreated candidate leakage intervals in the candidate leakage interval set, a new target leakage interval is determined according to the plugging priority value. When there are no other candidate leakage intervals in the candidate leakage interval set, the current plugging operation is terminated.

[0053] See attached document Figure 8 In specific implementations, steps S4 and S5 provided by this invention may include the following steps: S41. Move the dual-channel drill bit assembly axially using the drilling rig lifting equipment to move the bypass sub 3 to the target leakage range determined in S3; position the nozzle 303, located on the side wall of the sub body 302, at the depth center of the target leakage range; prepare the plugging grout containing sealing material in the ground grouting system; stop the rotation of the dual-channel drill bit assembly and keep the outer pipe body 109 fixed; confirm that the outer channel injection valve 113 is closed and release the pressure in the outer channel injection pipe 114; connect the outlet of the ground grouting pump unit to the union joint 115 and the outer channel injection pipe 114 through the valve manifold; read the inlet pressure of the inner channel 118 recorded by the top drive system and the inlet pressure of the outer channel 117 recorded by the ground grouting pump unit; First, apply test pressure to the inner channel 118 while keeping the outer channel injection valve 113 closed; monitor the change in inlet pressure of the outer channel 117; after releasing the test pressure in the inner channel 118, open the outer channel injection valve 113 and apply the same test pressure through the outer channel 117, while monitoring the change in inlet pressure of the inner channel 118; the test pressure is higher than the minimum identifiable pressure increment of the pressure measurement system. The inlet test pressure of the inner channel 118 and the inlet test pressure of the outer channel 117 are both lower than the allowable working pressure of the dual-channel connector 1; the downhole equivalent pressure increment calculated by the inner channel reference hydraulic pressure loss model or the outer channel reference hydraulic pressure loss model is lower than the safe pressure limit corresponding to the estimated formation fracture pressure at the depth of nozzle 303. The pressure increment at the inlet of the non-pressurized channel shall not exceed the allowable proportion of the pressure increment at the inlet of the pressurized channel. The allowable proportion shall be determined based on the ratio of the maximum pressure response of the non-pressurized channel to the test pressure of the pressurized channel during the sealing test before the dual-channel connector 1 is lowered into the well. When the pressure state remains stable within 3 to 5 minutes, it is confirmed that the inner channel 118 and the outer channel 117 are in a hydraulically isolated state. After the hydraulic isolation state test is completed, the test pressure of the outer channel 117 shall be released so that the inlet pressure of the inner channel 118 and the inlet pressure of the outer channel 117 are restored to the basic values ​​before grouting, and then S42 shall be executed.

[0054] S42. Start the surface grouting pump set and pump a quantitative amount of plugging slurry into the outer channel 117; the plugging slurry flows downward along the outer channel 117 to the bypass section 3, and then flows through the bypass flow channel 304 and the nozzle 303 in sequence; the plugging slurry enters the leakage channel of the target leakage interval from the nozzle 303; a single grouting is carried out in a constant volume pulse manner; the theoretical pore volume of the target leakage interval is obtained by numerical integration of the logging sonic porosity and the geometric volume of the target leakage interval, and the theoretical pore volume is used as the initial reference for the single grouting volume; before formal grouting, a test grouting is carried out through the outer channel 117 at a low flow rate; The low-displacement rate starts from the lowest displacement rate that can be continuously and stably pumped through the outer channel 117, and gradually increases as long as the squeezing pressure at the depth of nozzle 303 does not exceed the upper limit of the allowable injection pressure. The test injection is stopped when any of the following occurs: the squeezing pressure rise rate exceeds the allowable fluctuation range of the pressure rise rate in the previous stable test injection stage; the wellhead return discharge rate no longer increases with the test injection discharge rate; the pressure decay tends to stabilize after the pump is stopped; the effective injectable volume of the target leakage interval is determined by deducting the transient volume caused by well fluid compression and tubing elastic deformation from the difference between the cumulative test injection volume and the cumulative wellhead return volume after well fluid transmission time correction; the single grouting volume is set to 30% to 50% of the effective injectable volume; the inlet pressure data of the outer channel 117 is collected in real time during the grouting process. The external channel reference hydraulic pressure loss model is called to calculate the squeezing pressure at the depth of nozzle 303; the discharge rate of the ground grouting pump group is adjusted according to the calculation result to keep the squeezing pressure within the effective safe injection window determined by S3; when the squeezing pressure reaches the pressure warning value, the discharge rate of the ground grouting pump group is reduced through the frequency converter. The pressure warning value is the pressure value after deducting the maximum delayed pressure increment and the measurement error of the squeezing pressure from the upper limit of the allowable injection pressure; the maximum delayed pressure increment is determined based on the maximum continued increase in pressure after the ground grouting pump set reduces its discharge rate and before the squeezing pressure begins to decrease; if the squeezing pressure still reaches or exceeds the upper limit of the allowable injection pressure after the discharge rate of the ground grouting pump set is reduced, or if the squeezing pressure continues to increase, the pumping of plugging grout into the external channel 117 is stopped.

[0055] S43. During the pumping of plugging slurry in the outer channel 117, the top drive system is controlled to synchronously pump clean drilling fluid through the inner channel 118; the drilling fluid flows downward along the inner channel 118, passing sequentially through the sub-body 302, drill collar 4, and screw drill string 5, and is discharged into the bottom annulus from the end of the drill bit 6; the drilling fluid flows upward from the bottom of the well along the wellbore annulus, and forms a composite flow with the plugging slurry discharged from the nozzle 303 in the target leakage zone; the top drive system discharge rate is adjusted according to the annulus flow velocity in the target leakage zone; When the annular velocity is less than the gravity settling velocity of the plugging slurry solid particles, increase the injection rate of inner channel 118; when the annular velocity is greater than the critical velocity for erosion resistance of the sealing structure, decrease the injection rate of inner channel 118; control the annular velocity of the target leakage zone between the gravity settling velocity of the plugging slurry solid particles and the critical velocity for erosion resistance of the sealing structure; the gravity settling velocity of the plugging slurry solid particles is calculated based on the particle size, density, drilling fluid density, and rheological parameters of the plugging material, or determined by a ground settling test using the same plugging slurry formulation, drilling fluid properties, and bottom hole temperature conditions; The critical flow velocity for the plugging structure to resist erosion was determined through a surface erosion test. The surface erosion test used the same plugging slurry formulation, drilling fluid properties, temperature conditions, and settling or curing time as the downhole operation. The erosion flow velocity was gradually increased, and the flow velocity at which the plugging structure began to show continuous material loss or the test leakage volume increased again was determined as the critical flow velocity for the plugging structure to resist erosion. When the gravity settling velocity of the plugging slurry solid particles was less than the critical flow velocity for the plugging structure to resist erosion, the annular target safe flow velocity was determined between the gravity settling velocity of the plugging slurry solid particles and the critical flow velocity for the plugging structure to resist erosion. When the gravity settling velocity of the solid particles in the plugging slurry is greater than or equal to the critical flow velocity for erosion resistance of the plugging structure, adjust the particle size, density, or rheological parameters of the plugging material. If the annular flow velocity control window still cannot be formed after adjustment, stop the current plugging pulse.

[0056] S44. The controller starts the flow rate dynamic calculation module and calculates the target matching displacement of the inner channel 118 based on the real-time grouting parameters of the outer channel 117; the top drive system adjusts the actual injection displacement of the inner channel 118 according to the target matching displacement; the calculation formula for the target matching displacement is as follows: ; In the formula, Match the target displacement for inner channel 118; To ensure a safe flow velocity for the target in the annular space, in this embodiment, The value ranges from 0.8 m / s to 1.5 m / s; The annular cross-sectional area of ​​the wellbore corresponding to the position where the annular flow velocity above nozzle 303 is calculated. The real-time injection rate of outer channel 117; the leakage rate of fluid injected into the formation from inner channel 118 and outer channel 117 before reaching the annular velocity calculation position above nozzle 303, when the fluid enters the formation. Take a positive value; calculate based on the real-time injection discharge rate of inner channel 118, the real-time injection discharge rate of outer channel 117, and the wellhead return discharge rate after well fluid transmission time correction, and deduct the transient flow rate changes caused by well fluid compression and tubing elastic deformation. If the calculation result is less than 0, treat it as 0; When the calculated target displacement of inner channel 118 exceeds the allowable displacement of the top drive system, the actual injection displacement of inner channel 118 is limited to within the allowable displacement of the top drive system, and the injection displacement of outer channel 117 is reduced; if the actual injection displacement of inner channel 118 and the injection displacement of outer channel 117 still cannot meet the safe flow velocity of the annular target after adjusting them, the current blocking pulse is stopped.

[0057] S51. After a single sealing pulse grouting operation is completed, the fluid source is switched through the surface valve manifold to stop pumping the plugging grout into the external channel injection pipe 114 and open the drilling fluid injection valve; the surface pump set is controlled to continuously pump clean drilling fluid through the external channel 117; the volume of drilling fluid pumped in is determined according to the sum of the volume of the external channel injection pipe 114, the volume of the external channel 117, the volume of the bypass flow channel 304, the effective volume of the surface manifold connected to the union joint 115, and the displacement volume margin. The displacement volume margin is determined based on the metering error of the surface pump set, the calculation error of the effective volume of the surface manifold, the calculation error of the volume of the external channel injection pipe 114, and the calculation error of the volume of the external channel 117; the clean drilling fluid pushes the residual plugging slurry downward along the external channel 117 and displaces it to the target leakage area through the nozzle 303; After the displacement is completed, the external channel 117 and the bypass flow channel 304 are restored to the clean drilling fluid flow state; the effective volume of the surface manifold is calculated based on the inner diameter and length of the surface manifold; when the plugging slurry is a particle bridging plugging slurry, S52 is executed after the pressure holding time ends; the pressure holding time is determined based on the time required for the particle bridging plugging slurry to form a stable bridging structure under the bottom hole temperature conditions; When the plugging slurry contains a coagulating or solidifying component, S52 shall be performed after the plugging slurry reaches its initial setting strength. The initial setting strength shall be determined based on the minimum strength required for the plugging slurry containing the coagulating or solidifying component to not suffer structural damage under the step disturbance of the S52 discharge rate, and shall be obtained through a surface strength test of the same plugging slurry formulation under bottom hole temperature conditions.

[0058] After the plugging slurry replacement operation is completed (S52), the isobaric registration difference identification program is started according to the waiting conditions determined in S51. Based on the parameter boundaries determined in S2, displacement step disturbances are alternately applied to the inner channel 118 and the outer channel 117. The dynamic response data of the inlet pressure of the inner channel 118 and the inlet pressure of the outer channel 117 are collected in real time. The interval relative leakage index solution model is called to calculate the real-time interval relative leakage index after the target leakage interval completes a single plugging pulse. The changes in the stable baseline of the inlet pressure of the inner channel 118, the stable baseline of the inlet pressure of the outer channel 117, the changes in the wellhead return displacement, and the real-time interval relative leakage index are recorded in the current test cycle, and the recorded data are stored in the controller.

[0059] S53. The controller identifies the mechanical blockage risk of the outer channel 117, the bypass flow channel 304, or the nozzle 303, as well as the sealing effectiveness status of the target leakage range, based on the changes in the inlet pressure of the inner channel 118, the changes in the inlet pressure of the outer channel 117, the real-time interval relative leakage index, and the wellhead return discharge rate. A decrease in the real-time interval relative leakage index, an increase in the wellhead return discharge rate, and a decrease in the total wellbore leakage all indicate that the change in the corresponding parameter exceeds the sum of the maximum fluctuation obtained by repeated identification under the same discharge rate and drilling fluid performance conditions by S2 and the measurement error of the data acquisition system. When the change in the inlet pressure of the outer channel 117 is greater than the alarm threshold and the change in the inlet pressure of the inner channel 118 is within the allowable fluctuation range of the initial baseline, the real-time interval relative leakage index and the wellhead return discharge rate are compared again. The alarm threshold is determined based on the drilling fluid yield value, ranging from 2 MPa to 3 MPa; the initial baseline is allowed to fluctuate within ±2% to ±5% of the base pressure; when the inlet pressure of the outer channel 117 increases, the real-time interval relative leakage index does not decrease, and the wellhead return flow rate does not increase, it is determined that there is a risk of mechanical blockage in the outer channel 117, the bypass flow channel 304, or the nozzle 303; stop pumping plugging slurry into the outer channel 117, and pump clean drilling fluid into the outer channel 117 for forward flushing; after the forward flushing is completed, retest the inlet pressure of the outer channel 117 under the same injection flow rate; When the inlet pressure of outer channel 117 recovers to the allowable fluctuation range corresponding to the reference hydraulic pressure loss model of outer channel, the sealing operation continues; when the inlet pressure of outer channel 117 fails to recover to the allowable fluctuation range corresponding to the reference hydraulic pressure loss model of outer channel, the sealing operation is stopped and the dual-channel drill string assembly is retrieved for inspection; when the change in inlet pressure of outer channel 117 and the change in inlet pressure of inner channel 118 increase synchronously, the real-time interval relative leakage index is lower than the initial interval relative leakage index, and the wellhead return discharge increases or the total wellbore leakage decreases under the same total injection discharge, it is determined that the target leakage interval has formed a pressure-bearing sealing structure, and a sealing effective status indicator is output.

[0060] S54. Adjust the injection parameters of the next plugging pulse based on the change in the relative leakage index of the real-time interval; the plugging qualification threshold is determined within the range of 0.01 L / (s·MPa) to 0.05 L / (s·MPa) based on the allowable leakage in the drilling engineering design and the maximum fluctuation of the relative leakage index of the interval obtained from repeated identification in S2; when the real-time interval relative leakage index is lower than the plugging qualification threshold, stop the pulse grouting operation of the target leakage interval; when the real-time interval relative leakage index is higher than the plugging qualification threshold, calculate the set injection volume of the next plugging pulse; the set injection volume of the next plugging pulse is calculated according to the following formula: ; In the formula, This represents the total pumping volume of the ground pump unit in the next sealing pulse. S42 determines the initial plugging pulse injection volume based on the effective injectable volume of the target leakage interval; This represents the current measured real-time relative leakage index. The relative leakage index of the target leakage interval before the first blocking pulse is applied; In this embodiment, as a manifold volume compensation margin, Based on the residual plugging slurry volume in the ground manifold and external channel injection pipe 114, as well as the metering error of the ground pump set, within 0.5m... 3 Up to 1m 3 Determined within the scope; deduct The effective injection volume of the plugging grout shall not exceed the effective injectable volume of the target leakage range; during the execution of the next plugging pulse, when the squeezing pressure at the depth where nozzle 303 is located reaches the upper limit of the allowable injection pressure, the plugging grout injection shall be stopped immediately.

[0061] See attached document Figure 9 In specific implementations, step S6 provided by the present invention may include the following steps: S61. The controller extracts the target leakage interval data that has reached the qualified blocking threshold and deletes the corresponding target leakage interval from the candidate leakage interval set established in S3; updates the candidate leakage interval set and checks whether the candidate leakage interval set is empty; if the candidate leakage interval set is not empty, returns to S2, re-implements differential identification for the remaining candidate leakage intervals, and updates the interval relative leakage index of the remaining candidate leakage intervals; then executes S3, updates the blocking priority value and determines the new target leakage interval; if the candidate leakage interval set is empty, determines that the real-time interval relative leakage index of all candidate leakage intervals has reached the qualified blocking threshold determined in S54, and performs the operation of switching the dual-channel connector 1 from the dual-injection dual-channel working state to the single-injection dual-channel working state.

[0062] S62. After all candidate leakage intervals are sealed, clean drilling fluid is pumped in through the outer channel 117 to flush the outer channel injection pipe 114, outer channel 117, bypass flow channel 304 and nozzle 303; the inlet pressure of the outer channel 117 is recorded at the current flushing discharge rate. When the inlet pressure of the outer channel 117 is within the allowable fluctuation range corresponding to the outer channel reference hydraulic pressure loss model, it is confirmed that the outer channel injection pipe 114, outer channel 117, bypass flow channel 304 and nozzle 303 remain connected. Clean drilling fluid is pumped into the inner channel 118 to flush the internal flow channels of the inner channel 118, drill collar 4, screw drill string 5, and drill bit 6. The inlet pressure of the inner channel 118 is recorded at the current flushing rate. If the inlet pressure of the inner channel 118 is within the allowable fluctuation range corresponding to the reference hydraulic pressure loss model of the inner channel, it is confirmed that the water holes of the inner channel 118, drill collar 4, screw drill string 5, and drill bit 6 remain connected. After flushing, the outer channel injection valve 113 is closed to release the pressure in the outer channel injection pipe 114, and the connection between the union 115 and the surface pipeline is disconnected. The outer pipe body 109 and the lower tubing connected to it are kept from rotating. The top drive is operated to rotate the upper connector body 111 relative to the outer pipe body 109 along the loosening direction of the upper connector male thread 110. The upper connector male thread 110 gradually unscrews the outer pipe body female thread 108. The threaded joint converts the rotational motion of the upper connector body 111 into axial upward motion; the upper connector body 111 pulls the central tube 107 relative to the outer tube body 109 and the inner tube string with the male thread 101 of the inner tube at the lower end to slide upward along the central axis; the bypass hole 106 of the central tube is disengaged from the sealing coverage of the sealing sleeve 105; the inner channel 118 and the outer channel 117 are reconnected; the drilling fluid pumped in by the top drive or angular drill pipe joint enters the inner channel 118 and the outer channel 117 respectively, and the dual-channel joint 1 returns to the single-injection dual-channel working state; the torque during the unscrewing process of the upper connector body 111 is monitored by the top drive torque sensor.

[0063] S63. Based on the type of plugging slurry used in the last plugging pulse, allow the slurry to settle or wait for it to set. For particle-bridging plugging slurries, allow them to settle for the pressure holding time determined in S51. For plugging slurries containing setting or solidifying components, wait for them to set according to the initial setting strength conditions determined in S51. After meeting the corresponding conditions, move the dual-channel drill string assembly through the plugged section. After completing wellbore cleaning, perform a full-section pressure-bearing capacity verification test. Control the top drive system to continuously pump drilling fluid at the test displacement, and collect the inlet pressure of inner channel 118, the conventional circulation injection displacement, and the conventional circulation return displacement. Based on the inner channel's reference hydraulic pressure loss model, convert the inlet pressure of inner channel 118 into the bottom hole additional pressure. Call the full-section equivalent pressure-bearing coefficient calculation model. The full-section equivalent pressure-bearing coefficient is calculated according to the following formula: ; In the formula, The equivalent bearing capacity coefficient for the entire well section; The bottom hole additional pressure is calculated by subtracting the reference hydraulic pressure loss corresponding to the inner channel 118, drill collar 4, screw drill tool 5 and drill bit 6 from the inlet pressure of the inner channel 118 under the test displacement. Where is the density of the drilling fluid; g is the acceleration due to gravity; This represents the current vertical depth of the wellbore. Inject displacement in a regular cycle during test conditions; This refers to the normal cyclic output displacement under test conditions; In this embodiment, the leakage penalty factor is used. The calibration was performed based on the injection rate, wellhead return rate, and bottom hole additional pressure data of well sections with no leakage and known leakage under different circulation rates, and the values ​​were determined within the range of 1.5 to 2.5.

[0064] The pressure-bearing capacity verification test of the entire well section was carried out by increasing the circulation discharge rate in stages. The circulation discharge rate of each stage was set within the calibrated discharge rate range of S14. The increment between two adjacent circulation discharge rates did not exceed the discharge rate difference between adjacent discharge rate test nodes in S14. The circulation discharge rate of each stage was maintained until the change in the inlet pressure of channel 118 and the return discharge rate at the wellhead did not exceed the maximum fluctuation obtained from repeated tests in S14 within one continuous wellbore fluid transmission time. During the test, the calculated bottom hole additional pressure shall not exceed the pressure increment of the estimated formation fracture pressure at the current test depth relative to the annulus pressure under the basic circulation state after deducting the safety margin, nor shall it exceed the upper limit of the bottom hole additional pressure calculated from the allowable working pressure of the dual-channel drill string assembly; the wellhead return discharge rate shall not be lower than the discharge rate after deducting the allowable leakage rate of the drilling engineering design from the conventional circulation injection rate, the wellbore leakage rate shall not be greater than the allowable leakage rate of the drilling engineering design, and the equivalent bearing capacity coefficient of the entire well section shall not be lower than the minimum value of the equivalent bearing capacity coefficient of the entire well section measured under the same circulation discharge rate in the well section without obvious leakage, after deducting the error of repeated testing, and the pressure bearing verification shall be deemed qualified. If the wellhead return flow rate is lower than the flow rate after deducting the allowable leakage from the drilling engineering design from the conventional circulation injection flow rate, or if the wellbore leakage is greater than the allowable leakage from the drilling engineering design, or if the equivalent pressure bearing coefficient of the entire well section is lower than the minimum value of the equivalent pressure bearing coefficient of the entire well section measured under the same circulation flow rate in well sections without significant leakage, after deducting the error from repeated testing, the pressure bearing verification is deemed unqualified, and the process is returned to S2 for differential identification to be reimplemented.

[0065] S64. After the pressure test is passed, resume drilling operations at the bottom of the well; lower the dual-channel drill string assembly to the bottom of the well using the drilling rig hoisting equipment; first establish drilling fluid circulation with a low discharge rate not lower than the minimum working discharge rate of the screw drill string 5 and not exceeding the normal drilling base discharge rate; when the inlet pressure of the top drive system does not exceed the benchmark circulation pressure and corresponding allowable fluctuation range determined according to the stable circulation data in S11 under the same well depth and discharge rate, and the difference between the wellhead return discharge rate and the injection discharge rate does not exceed the allowable leakage rate of the drilling engineering design, confirm that the circulation pressure and return discharge rate of the dual-channel drill string assembly meet the conditions for resuming drilling. The top drive system gradually increases the rotational speed of drill bit 6 and gradually applies drilling pressure to drill bit 6. The drilling pressure is set according to the hardness of the formation rock and the model of drill bit 6, with a value range of 50kN to 150kN. Drill bit 6 rotates and cuts the formation rock, producing cuttings. Drilling fluid discharged from nozzle 303 and the water hole of drill bit 6 carries cuttings and flows back up along the wellbore annulus to the surface system. The initial drilling stage is resumed, and the fluid level in the circulation pool is monitored in real time. When the fluid level in the circulation pool maintains dynamic balance within two drilling fluid circulation cycles, leakage identification and adaptive plugging operations are completed, and the system switches to continuous drilling mode.

[0066] See attached document Figure 10 To aid in understanding the technical solution of this invention, the following provides application examples of a wellbore multi-layer complex leakage dual-channel adaptive plugging device and method for drilling.

[0067] When drilling reached the depth of the lost circulation well, it encountered multiple complex lost circulation layers. The dual-channel drill string assembly was lowered to the section without lost circulation. After the dual-channel connector 1 was switched to the dual-injection dual-channel working state, the basic displacement was injected through channel 117 outside the surface pump set and the basic displacement was injected through channel 118 inside the top drive. A benchmark hydraulic pressure loss model was established through continuous and stable cyclic data acquisition. The current drilling fluid density was measured to confirm that the deviation between the wellhead return displacement and the injected displacement was within the allowable error range of the benchmark calibration.

[0068] The bypass sub 3 is lowered to the section of the well to be identified for leakage. While maintaining the basic discharge rate of the inner channel 118, the discharge rate of the outer channel 117 is increased stepwise. The equivalent annular pressure increment at the depth of the nozzle 303 is calculated using the benchmark hydraulic pressure loss model. After restoring the basic discharge rate, the discharge rate of the inner channel 118 is gradually increased at a constant acceleration. When the annular pressure increment generated at the bottom drill bit 6 is equal to the equivalent annular pressure increment generated by the disturbance of the nozzle 303 at the depth of the outer channel 117, the discharge rate is stopped. Based on the difference between the injection and return volumes measured under the two disturbances, the relative leakage index of the current identification section is calculated using the relative leakage index solution model. The bypass sub 3 is moved along the wellbore, and the relative leakage index of the adjacent identification sections is measured in the same way.

[0069] An anomaly detection threshold is set, and the relative leakage index of the identified interval is compared with the anomaly detection threshold. Identified intervals exceeding the anomaly detection threshold are marked as candidate leakage intervals. An equivalent leakage initiation pressure test is performed on the candidate leakage intervals. The equivalent leakage initiation pressure of the candidate leakage interval is measured by increasing the equivalent pressure with a preset pressure increment step. After the pump is stopped and the valve is closed and left to stand, the pressure retention coefficient of the candidate leakage interval is measured. According to the plugging priority value calculation formula, the relative leakage index, pressure retention coefficient and equivalent leakage initiation pressure of the candidate leakage interval are normalized. Then, they are weighted according to the leakage index weight coefficient, pressure release index weight coefficient and initiation pressure weight coefficient to obtain the plugging priority value of the candidate leakage interval. The candidate leakage interval with the largest plugging priority value is determined as the target leakage interval. The equivalent value of the fracture pressure is estimated by combining well logging data and the safety margin is deducted to set the upper limit of the allowable injection pressure. The equivalent leakage initiation pressure is extracted as the lower limit of the allowable injection pressure and the effective safe injection window is determined.

[0070] The nozzle 303 is aligned with the center of the target leakage zone. The theoretical pore volume of the target leakage zone is estimated by numerical integration, and the theoretical pore volume is used as the initial reference for the single injection volume. The effective injectable volume of the target leakage zone is determined by low-displacement test injection, and the single injection volume is set at 30% to 50% of the effective injectable volume. The ground grouting pump group is started to pump plugging slurry into the outer channel 117, and the squeezing pressure is monitored in real time and maintained within the effective safe injection window. At the same time, clean drilling fluid is pumped into the inner channel 118. The control system determines the target safe flow velocity in the annulus based on the real-time grouting parameters and controls the top drive system to adjust the injection displacement of the inner channel 118 to the target matching displacement.

[0071] After a single grouting is completed, a fixed amount of clean drilling fluid is pumped in through the external channel 117 to replace all the residual plugging slurry in the pipeline into the fracture. After standing and waiting for solidification, the displacement step disturbance differential identification is performed again to measure the real-time relative leakage index of the target leakage section. When the real-time relative leakage index is lower than the set sealing qualification threshold, it is determined that the sealing of the target leakage section has met the standard, and the pulse grouting of the target leakage section is terminated.

[0072] The control system removes the target leakage intervals that have met the standards from the candidate leakage interval set, automatically updates the remaining candidate leakage intervals as new target leakage intervals, and repeats the pulse grouting and differential identification verification process. After all candidate leakage intervals are sealed and meet the standards, the dual-channel connector 1 switches back to the single-injection dual-channel working state, and increases the circulation flow rate in stages to conduct a full-well section pressure-bearing capacity verification test. When the wellhead return flow rate is not lower than the flow rate after deducting the allowable leakage rate of the drilling engineering design from the conventional circulation injection flow rate, the wellbore leakage rate is not greater than the allowable leakage rate of the drilling engineering design, and the equivalent pressure-bearing coefficient of the entire well section is not lower than the qualified lower limit determined by S63, continuous drilling resumes.

[0073] While specific embodiments of the present invention have been described above, those skilled in the art should understand that these specific embodiments are merely illustrative. Those skilled in the art can omit, substitute, and modify the details of the above methods and systems in various ways without departing from the principles and essence of the present invention. For example, combining the above method steps to perform substantially the same function and achieve substantially the same result using substantially the same method falls within the scope of the present invention.

Claims

1. A method for adaptive plugging of complex multi-layered leakage in wellbores via dual-channel drilling, characterized in that the method... include: The dual-channel drilling assembly was lowered into the well section without leakage in the wellbore, and switched to the dual-injection dual-channel working state. Fluid was injected into the inner channel (118) and the outer channel (117) respectively, and the benchmark hydraulic pressure loss model of the inner channel (118) and the outer channel (117) was established. Move the bypass section (3) to the well section to be identified for leakage, and apply displacement step disturbances to the inner channel (118) and outer channel (117) respectively based on the benchmark hydraulic pressure loss model to form equal equivalent annular pressure increments and obtain leakage response. Calculate the interval relative leakage index of the well section between the drill bit (6) and the nozzle (303). Candidate leakage intervals are screened based on the relative leakage index of the intervals, and the equivalent leakage initiation pressure is tested. The blocking priority value is calculated, and the target leakage interval is determined. Calculate the lower limit and upper limit of the allowable injection pressure for the target leakage interval. Between the lower limit and the upper limit of the allowable injection pressure, inject plugging slurry into the target leakage interval through the outer channel (117) and adjust the drilling fluid discharge rate injected synchronously through the inner channel (118) based on the annular flow velocity of the target leakage interval. After a single plugging pulse ends, the plugging slurry is replaced through the external channel (117) and differential identification is re-implemented to determine the mechanical blockage risk and formation plugging effect, and to adjust the injection volume of the next plugging pulse. Grouting is stopped once the target leakage section meets the sealing requirements. The remaining candidate leakage sections are sealed in sequence to complete well cleaning and pressure testing. Normal drilling resumes after the pressure testing is passed.

2. The wellbore multi-layer complex leakage dual-channel adaptive plugging method according to claim 1, characterized in that, The steps for establishing the reference hydraulic pressure loss models for the inner channel (118) and the outer channel (117) include: Establish a reference hydraulic pressure loss model for the inner channel including the pressure loss of the drill bit (6) water hole and a reference hydraulic pressure loss model for the outer channel including the pressure loss of the nozzle (303); The displacement step disturbance is applied to the inner channel (118) and outer channel (117) respectively based on the benchmark hydraulic pressure loss model to form an equal equivalent annular pressure increment and obtain the leakage response. The interval relative leakage index of the well section between the drill bit (6) and the nozzle (303) is calculated, including: Keep the basic displacement of the inner channel (118) unchanged, and apply a displacement step disturbance to the basic displacement of the outer channel (117); after restoring the basic cycle, keep the basic displacement of the outer channel (117) unchanged, and apply a displacement step disturbance to the basic displacement of the inner channel (118); Adjust the amplitude of the two displacement step disturbances to form the same equivalent annular pressure increment at the depth of the nozzle (303); Substitute the leakage flow increments corresponding to the two disturbances into the interval relative leakage index solution model to calculate the interval relative leakage index between the nozzle (303) and the drill bit (6) in the current identification interval.

3. The wellbore multi-layer complex leakage dual-channel adaptive plugging method according to claim 1, characterized in that, The steps of screening candidate leakage intervals based on the relative leakage index, testing the equivalent leakage initiation pressure, calculating the blocking priority value, and determining the target leakage interval include: Based on the formation permeability and leakage data of the target block, an anomaly detection threshold is set, and the intervals whose relative leakage index exceeds the anomaly detection threshold are listed as candidate leakage intervals. The equivalent leakage start pressure of the candidate leakage range is tested by increasing the equivalent pressure in a preset pressure increment step, and the pressure retention coefficient of the candidate leakage range is measured after the pump is stopped, the valve is closed and the area is left to stand. The relative leakage index, equivalent leakage initiation pressure, and pressure holding coefficient of the candidate leakage interval are normalized and weighted according to the plugging priority value calculation formula to obtain the plugging priority value. The candidate leakage interval with the largest plugging priority value is determined as the target leakage interval.

4. The wellbore multi-layer complex leakage dual-channel adaptive plugging method according to claim 1, characterized in that, The steps of calculating the lower and upper limits of the allowable injection pressure for the target leakage range, pulse-injecting plugging slurry into the target leakage range through the outer channel (117) between the lower and upper limits of the allowable injection pressure, and adjusting the drilling fluid discharge rate synchronously injected through the inner channel (118) based on the annular flow velocity of the target leakage range include: The sum of the equivalent leakage initiation pressure and the injection pressure margin of the target leakage interval is determined as the lower limit of the allowable injection pressure. The pressure increment of the estimated formation fracture pressure at the depth of the nozzle (303) relative to the annular pressure under the basic circulation state, minus the safety margin, is determined as the upper limit of the allowable injection pressure. The effective safe injection window is determined. The single injection volume is set to 30% to 50% of the effective injectable volume of the target leakage interval. Within the effective safe injection window formed by the lower limit of the allowable injection pressure and the upper limit of the allowable injection pressure, the pulse injection of plugging grout is completed through the external channel (117). The annular flow velocity of the target leakage interval is controlled between the gravity settling velocity of the solid particles of the plugging slurry and the critical flow velocity of the plugging structure to resist erosion. The target matching displacement of the inner channel (118) is calculated, and the top drive system is fed back to adjust the drilling fluid displacement injected synchronously into the inner channel (118).

5. The wellbore multi-layer complex leakage dual-channel adaptive plugging method according to claim 1, characterized in that, After the single plugging pulse ends, the steps of replacing the plugging slurry through the external channel (117) and re-implementing differential identification to determine the mechanical blockage risk and formation plugging effect, and adjusting the injection volume of the next plugging pulse include: After the pressure holding time or initial setting strength conditions are met according to the type of plugging grout, the real-time relative leakage index of the interval is re-measured by differential identification to determine the sealing effectiveness of the target leakage interval. When the inlet pressure of the outer channel (117) increases, and the relative leakage index of the real-time interval does not decrease and the wellhead return discharge does not increase, it is determined that there is a risk of mechanical blockage, and clean drilling fluid is pumped into the outer channel (117) for positive flushing. The plugging qualification threshold is set based on the allowable leakage of drilling engineering and the maximum fluctuation of the interval relative leakage index. When the real-time interval relative leakage index is higher than the plugging qualification threshold, the set injection volume of the next plugging pulse is calculated based on the ratio of the currently measured real-time interval relative leakage index to the interval relative leakage index before the first plugging pulse.

6. The wellbore multi-layer complex leakage dual-channel adaptive plugging method according to claim 1, characterized in that, After the target leakage section meets the sealing requirements, grouting is stopped. The remaining candidate leakage sections are sealed in sequence to complete well cleaning and pressure testing. After the pressure testing is passed, normal drilling is resumed. The steps include: Based on the allowable leakage in drilling engineering, a qualified sealing threshold is set. When the real-time interval relative leakage index of the target leakage interval is lower than the qualified sealing threshold, pulse grouting of the target leakage interval is stopped, and the target leakage interval is removed from the candidate leakage interval set. Re-apply differential identification to the remaining candidate missing intervals, update the blocking priority value, and block them sequentially. After all candidate leakage intervals are plugged, the dual-channel connector (1) is switched back to the single-injection dual-channel working state. The circulation discharge is increased in stages to carry out the pressure-bearing capacity verification test of the whole well section. When the discharge returned from the wellhead is not lower than the discharge after deducting the leakage allowable by the drilling engineering design from the conventional circulation injection discharge, the wellbore leakage is not greater than the leakage allowable by the drilling engineering design, and the equivalent pressure-bearing coefficient of the whole well section is not lower than the lower limit of the qualified, the pressure-bearing verification is qualified and continuous drilling is resumed.

7. A multi-layered complex leakage dual-channel adaptive plugging device for wellbore drilling, characterized in that: The apparatus for the wellbore multi-layer complex leakage dual-channel adaptive plugging method according to any one of claims 1 to 6 includes: The components connected from top to bottom are a double-channel connector (1), at least one double-channel drill pipe (2), a bypass short section (3), and a lower drill string assembly; The dual-channel connector (1) is provided with a central tube (107), and the dual-channel drill rod (2) is provided with a drill rod inner tube (206) coaxially inside, forming an inner channel (118) and an outer channel (117) that are physically isolated from each other within the device. The dual-channel connector (1) has a single-injection dual-channel working state and a dual-injection dual-channel working state; The bypass sub (3) has a nozzle (303) on the side of the sub body (302). The inner channel (118) extends downward along the center of the sub body (302) and is connected to the internal flow channel of the lower drill assembly in sequence. The outer channel (117) is connected to the nozzle (303) inside the bypass sub (3).

8. The wellbore multi-layer complex leakage dual-channel adaptive plugging device according to claim 7, characterized in that, The dual-channel connector (1) includes an outer tube body (109), an upper connector body (111), a central tube (107), an inner tube column with a male thread (101) on the lower end, a connector connecting flange (103), a sealing rubber sleeve (105), an outer channel injection valve (113), an outer channel injection pipe (114), and a union (115). The central tube (107) and the internal space of the inner tube column connected to the lower end of the central tube (107) together form the inner channel (118); the annular space between the outer wall of the central tube (107) and the inner wall of the outer tube body (109), and the annular space between the outer wall of the inner tube column and the inner wall of the outer tube body (109) are continuously connected and together form the outer channel (117); a central tube bypass hole (106) is opened on the side wall of the central tube (107). The sealing sleeve (105) is fixedly installed at the upper end of the inner tube column and located inside the outer tube body (109), and the sealing sleeve (105) is sleeved on the outer periphery of the central tube (107); the joint connecting flange (103) is fixedly installed between the inner tube column with the male thread (101) of the inner tube at the lower end and the outer tube body (109), and the joint connecting flange (103) is provided with a joint flange flow hole (104); the outer tube body (109) is provided with an outer channel injection pipe (114) communicating with the outer channel (117) on the side; an outer channel injection valve (113) is installed on the outer channel injection pipe (114); the outer end of the outer channel injection pipe (114) is connected to a union joint (115). The upper connector body (111) is provided with an upper connector female thread (112) at its upper end, and the upper connector male thread (110) at the lower end of the upper connector body (111) is screwed into the outer tube body female thread (108) on the outer tube body (109); the central tube (107) is connected to the upper connector body (111); when the upper connector body (111) moves axially relative to the outer tube body (109), it drives the central tube (107) to slide axially relative to the outer tube body (109) and the inner tube column with the connector inner tube male thread (101) at its lower end; the central tube bypass hole (106) enters the coverage and sealing range of the sealing rubber sleeve (105); The lower end of the dual-channel connector (1) is provided with an inner male thread (101) and an outer male thread (102); a connector sealing ring (116) is provided at the sealing connection position of the dual-channel connector (1).

9. The wellbore multi-layer complex leakage dual-channel adaptive plugging device according to claim 7, characterized in that, The dual-channel drill pipe (2) includes an outer drill pipe (205), an inner drill pipe (206), and a drill pipe connecting flange (203). The inner tube (206) of the drill rod is coaxially disposed inside the outer tube (205) of the drill rod; the drill rod connecting flange (203) is fixedly connected to the outer tube (205) and the inner tube (206) of the drill rod respectively; the drill rod connecting flange (203) is provided with a drill rod flange flow hole (204) that connects to the outer channel (117). Two adjacent dual-channel drill pipes (2) are connected by screwing the male thread (201) of the inner tube of the drill pipe to the female thread (207) of the inner tube of the drill pipe, and by screwing the male thread (202) of the outer tube of the drill pipe to the female thread (208) of the outer tube of the drill pipe; a drill pipe sealing ring (209) is provided at the connection position of the two adjacent dual-channel drill pipes (2). The lower end of the dual-channel drill rod (2) is provided with a male thread (201) for the inner tube of the drill rod and a male thread (202) for the outer tube of the drill rod; the upper end of the dual-channel drill rod (2) is provided with a female thread (207) for the inner tube of the drill rod and a female thread (208) for the outer tube of the drill rod.

10. The wellbore multi-layer complex leakage dual-channel adaptive plugging device according to claim 7, characterized in that, The bypass stub (3) includes a stub body (302); The outer female thread (305) of the short section body (302) at the upper end of the short section is sealed to the drill pipe outer tube male thread (202) of the double channel drill pipe (2); the inner female thread (306) of the short section body (302) at the upper end of the short section is sealed to the drill pipe inner tube male thread (201) of the double channel drill pipe (2); a short section sealing ring (307) is provided at the connection position between the double channel drill pipe (2) and the bypass short section (3); The male thread (301) at the lower end of the short section body (302) is connected to the female thread at the upper end of the lower drill bit assembly; The short section body (302) has a bypass flow channel (304) that communicates with the outer channel (117) and the bypass flow channel (304) is connected to the nozzle (303) located on the side of the short section body (302).

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