A wellbore safety gas production coordinated regulation method and system for horizontal well pressure reduction production

Abstract

The present application relates to the technical field of oil and gas exploitation, in particular to a wellbore safety gas production collaborative regulation method and system for horizontal well pressure reduction exploitation. The method comprises the following steps: obtaining reservoir parameters, wellbore parameters and production parameters of a natural gas hydrate horizontal well exploitation area, and then determining the uplift driving amount of the evaluation unit around the horizontal well; identifying the formation uplift front according to the uplift driving amount of the adjacent evaluation unit and the corresponding vertical displacement change trend, and then calculating the front edge advancing speed of the formation uplift front and the front edge influence length in the axial direction of the horizontal well; constructing a collaborative regulation index according to the front edge advancing speed, the wellbore bending curvature of the wellbore, the casing contact pressure and the gas production contribution per unit pressure drop; in response to the collaborative regulation index reaching the preset regulation level, determining the regulation range of the bottom hole pressure difference of the horizontal well based on the front edge influence length, and executing the corresponding hierarchical regulation action.

Description

Technical Field

[0001] This invention relates to the field of oil and gas extraction technology, specifically to a method and system for coordinated control of wellbore safety and gas production in horizontal well depressurization extraction. Background Technology

[0002] Natural gas hydrates, as an unconventional natural gas resource with enormous potential energy value, are found in porous media reservoirs on the seabed or in permafrost zones, and have become an important research subject in the field of energy development. Among existing development technologies, depressurization extraction is considered one of the more promising extraction methods due to its relatively simple process and the fact that it does not require continuous injection of chemical reagents or heat into the reservoir. Horizontal wells have attracted attention in natural gas hydrate development because they can increase the drainage area and improve single-well productivity. In particular, when the horizontal well section is arranged to traverse the hydrate reservoir development zone, the contact area between the wellbore and the reservoir is significantly increased, providing favorable conditions for improving gas production efficiency.

[0003] However, natural gas hydrate reservoirs generally exhibit unique mechanical properties of weak cementation or lack of diagenesis, resulting in low reservoir skeleton strength. During depressurization, the continuous effect of the bottom hole pressure differential disrupts the original thermodynamic equilibrium, driving hydrate decomposition and releasing methane gas and some free water. This decomposition process then triggers a series of complex physical field coupling responses: gas phase, water phase, and undecomposed hydrate coexist in the pore space, forming complex multiphase flow dynamics; pore fluid pressure changes due to gas generation and migration; hydrate saturation gradually decreases with the decomposition process; simultaneously, the effective stress on the reservoir skeleton gradually increases due to the decay of pore pressure, leading to mechanical response deformation of the reservoir.

[0004] Based on the aforementioned extraction mechanism, existing technologies primarily focus on improving gas production efficiency and ensuring the normal operation of drainage equipment. Specifically, many existing solutions use gas production as the core control indicator, adjusting the depressurization rate or production regime according to changes in gas production. Other solutions use bottom-hole flowing pressure or bottom-hole pressure differential as direct control parameters, determining the production pressure differential threshold based on the rated capacity of the drainage equipment. Still other solutions address sand control requirements, preventing excessive sand production and wellbore damage by controlling the pressure differential. Furthermore, some solutions combine bottom-hole microwave heating with depressurization methods, dynamically adjusting the heating power based on production changes to enhance hydrate decomposition efficiency. While these solutions can address gas production regulation issues in hydrate depressurization extraction to some extent, their limitations in coordinating wellbore safety and gas production efficiency become increasingly apparent as extraction progresses towards more complex reservoir conditions, the proportion of horizontal wells increases, and reservoir mechanical responses become more significant.

[0005] Specifically, existing technologies fail to synergistically consider wellbore integrity assurance and gas production efficiency improvement. Reservoir deformation caused by hydrate decomposition is not uniform but exhibits significant spatial differences and temporal evolution characteristics. The decomposition-affected zone typically extends outward from the wellbore's vicinity, resulting in a non-uniform distribution of reservoir uplift or subsidence deformation. Horizontal wellbores, due to their trajectory characteristics, may have curved sections. The spatial coupling effect between the wellbore's curvature and reservoir uplift deformation leads to abnormal contact pressure distribution between the casing and the wellbore. This contact pressure may exceed safety limits in localized areas, causing casing compression deformation or even wellbore instability. Furthermore, existing technologies, when setting depressurization rates or production differentials, primarily rely on the mechanical capabilities of drainage equipment, sand control requirements, or changes in gas production, rarely considering the economic indicator of gas production contribution per unit pressure drop. This results in situations where increased depressurization does not lead to a proportional increase in gas production, but rather exacerbates the risk of reservoir mechanical instability. More importantly, existing technologies lack a closed-loop control mechanism that can directly convert the dynamic identification results of the formation uplift front into bottom hole pressure differential control actions. This makes it impossible to dynamically adjust the production regime based on real-time monitoring of reservoir mechanical response in order to balance wellbore safety and gas production efficiency.

[0006] Therefore, how to establish a collaborative control mechanism that can simultaneously characterize wellbore safety risks and gas production efficiency during the depressurization production of natural gas hydrate horizontal wells, effectively link the identification results of formation uplift front with the graded control of bottom hole pressure difference, and take into account gas production efficiency while ensuring the integrity of the horizontal wellbore, has become a technical problem that urgently needs to be solved by those skilled in the art. Summary of the Invention

[0007] To address the shortcomings of existing methods and the needs of practical applications, this invention provides a method for coordinated control of wellbore safety and gas production in horizontal well depressurization production, comprising the following steps: Reservoir parameters, wellbore parameters, and production parameters of the production area of ​​a horizontal well for natural gas hydrates are obtained. Based on these parameters, the uplift drive of the wellbore evaluation unit of the horizontal well is determined. The formation uplift front is identified based on the uplift drive and corresponding vertical displacement trends of adjacent evaluation units. The forward advance velocity and the forward influence length along the axial direction of the horizontal well are calculated based on the identified uplift front. A coordinated control index is constructed based on the forward advance velocity, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop. In response to the coordinated control index reaching a preset control level, the control range for the bottom hole differential pressure of the horizontal well is determined based on the forward influence length, and graded control actions corresponding to the control level are executed. The control range includes a local well section or the entire well.

[0008] Optionally, the well perimeter evaluation unit is obtained by dividing the well perimeter formation of the horizontal well based on spatial location, and the evaluation unit includes at least multiple evaluation units with different radial distances; Determining the uplift drive of the wellbore evaluation unit of the horizontal well includes: The changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton are determined for each evaluation unit. The changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton are weighted and fused to obtain the uplift driving amount of each evaluation unit.

[0009] Optionally, the plurality of evaluation units include at least an inner well perimeter evaluation unit, a middle well perimeter evaluation unit, and an outer well perimeter evaluation unit; For the wellbore inner zone evaluation unit, the weights of the pore pressure change, hydrate saturation change, and reservoir skeleton effective stress change during weighted fusion are 0.30, 0.40, and 0.30, respectively; for the wellbore middle zone evaluation unit, the weights are 0.32, 0.33, and 0.35, respectively; and for the wellbore outer zone evaluation unit, the weights are 0.28, 0.22, and 0.50, respectively.

[0010] Optionally, after obtaining the uplift driving force of each evaluation unit through weighted fusion, the process further includes: The uplift driving amount is corrected by a position correction coefficient based on the spatial orientation of the evaluation unit relative to the horizontal wellbore.

[0011] Optionally, identifying the formation uplift front based on the uplift driving amount and corresponding vertical displacement change trend of adjacent evaluation units includes: The boundary of the area that meets the conditions is determined as the uplift front only when the difference in the uplift driving amount between adjacent evaluation units is greater than the preset difference threshold, and the vertical displacement change trend at the corresponding location meets the preset displacement change rate threshold, and this condition is met for N consecutive sampling time steps. Here, N is an integer greater than or equal to 2.

[0012] Optionally, the step of calculating the leading edge advance velocity of the formation uplift front and the leading edge influence length along the axial direction of the horizontal well, based on the identified formation uplift front, includes: The advancement speed of the formation uplift front is determined based on the change in spatial distance relative to the horizontal well at continuous sampling times; the length of the continuous evaluation unit that meets the preset front identification conditions along the axial direction of the horizontal well is counted to determine the front influence length.

[0013] Optionally, the construction of coordinated control indicators based on the leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop includes: The leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are converted into dimensionless parameters. The dimensionless parameters are then weighted and summed to obtain the coordinated control index. To characterize insufficient gas production efficiency, the weight of the gas production contribution per unit pressure drop is assigned a negative correlation. When wellbore integrity has a high priority, the weights corresponding to the leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are 0.25, 0.25, 0.30, and 0.20, respectively. When the wellbore safety condition is stable and gas production efficiency has a high priority, the weights are 0.20, 0.20, 0.25, and 0.35, respectively.

[0014] Optionally, the coordinated regulation index is a dimensionless index, and the preset regulation level is divided at least according to the first regulation level threshold and the second regulation level threshold. The step of responding to the coordinated control indicator reaching a preset control level and executing corresponding graded control actions includes: When the coordinated control index is less than or equal to the first control level threshold, it corresponds to a lower risk level, and the current bottom hole pressure differential or pressure reduction rate is maintained; when the coordinated control index is greater than the first control level threshold and less than or equal to the second control level threshold, it corresponds to a higher risk level, and the pressure reduction rate, step-wise backpressure, or local pressure stabilization is implemented; when the coordinated control index is greater than the second control level threshold, it corresponds to an even higher risk level, and segmented production switching is implemented.

[0015] Optionally, in response to the coordinated control index reaching a preset control level, determining the control range for the bottom hole pressure differential of the horizontal well based on the leading edge influence length, and executing a graded control action corresponding to the control level, includes: When it is determined that bottom hole pressure differential adjustment needs to be performed and the leading edge influence length only covers a portion of the horizontal well section, local pressure stabilization or segmented production switching is performed on the portion of the well section; when the leading edge influence length covers the entire horizontal well section, the depressurization rate or bottom hole pressure differential of the entire well is adjusted.

[0016] Secondly, to efficiently execute the wellbore safety gas production coordination and control method for horizontal well depressurization mining provided by this invention, this invention also provides a wellbore safety gas production coordination and control system for horizontal well depressurization mining, comprising: an input device, an output device, a processor, and a memory, wherein the input device, output device, processor, and memory are interconnected, and the memory stores program instructions used for the wellbore safety gas production coordination and control method for horizontal well depressurization mining. The wellbore safety gas production coordination and control system for horizontal well depressurization mining of this invention has a compact structure and stable performance, and can stably execute the wellbore safety gas production coordination and control method for horizontal well depressurization mining provided by this invention, further enhancing the overall applicability and practical application capability of this invention.

[0017] This invention incorporates reservoir deformation front, wellbore stress state, and gas production efficiency into the control judgment, overcoming the limitations of single-index control. By identifying the formation uplift front in real time and correlating wellbore bending with casing stress, it can provide early warning and control of risks, preventing wellbore damage. It combines the gas production contribution per unit pressure drop for control, avoiding ineffective pressure reduction and achieving a dynamic balance between gas production efficiency and engineering safety. It can perform segmented identification and control for heterogeneous reservoirs and is suitable for complex conditions such as marine areas and weak cementation. Attached Figure Description

[0018] Figure 1 A flowchart illustrating a method for coordinated control of wellbore safety and gas production in horizontal well depressurization mining, provided by an embodiment of the present invention; Figure 2 This is a framework diagram of a wellbore safety gas production collaborative control system for horizontal well depressurization mining, provided as an embodiment of the present invention. Detailed Implementation

[0019] Specific embodiments of the present invention will now be described in detail. It should be noted that the embodiments described herein are for illustrative purposes only and are not intended to limit the invention. In the following description, numerous specific details are set forth in order to provide a thorough understanding of the invention. However, it will be apparent to those skilled in the art that these specific details are not necessary to practice the invention. In other instances, well-known circuits, software, or methods have not been specifically described to avoid obscuring the invention.

[0020] Throughout this specification, references to "an embodiment," "an embodiment," "an example," or "an example" mean that a particular feature, structure, or characteristic described in connection with that embodiment or example is included in at least one embodiment of the invention. Therefore, the phrases "in an embodiment," "in an embodiment," "an example," or "an example" appearing in various places throughout the specification do not necessarily refer to the same embodiment or example. Furthermore, specific features, structures, or characteristics can be combined in one or more embodiments or examples in any suitable combination and / or sub-combination. Moreover, those skilled in the art will understand that the illustrations provided herein are for illustrative purposes and are not necessarily drawn to scale.

[0021] It should be understood that when a horizontal wellbore passes through a natural gas hydrate reservoir development zone, the natural gas hydrate reservoir is usually a weakly cemented or non-diagenetic porous medium. The hydrate decomposition process will cause changes in pore pressure, hydrate saturation, gas-water two-phase flow state and effective stress state of the reservoir skeleton. These changes will further affect the deformation state of the formation around the wellbore and may affect the bending state of the horizontal wellbore, the stress state of the casing and the production stability of the well section through the contact between the formation and the wellbore.

[0022] Therefore, in this invention, the bottom hole pressure differential control is not based solely on gas production or production pressure differential, but is determined by combining the evolution state of the formation uplift front, the length of the front influence, the wellbore curvature, the casing contact pressure, and the gas production contribution per unit pressure drop.

[0023] Please see Figure 1 This invention provides a method for coordinated control of wellbore safety and gas production in horizontal well depressurization production, comprising the following steps: S1. Obtain the reservoir parameters, wellbore parameters, and production parameters of the horizontal well production area for natural gas hydrates. Based on the reservoir parameters, wellbore parameters, and production parameters, determine the uplift drive of the wellbore evaluation unit of the horizontal well.

[0024] The formation around a horizontal wellbore is divided into multiple evaluation units based on radial distance, vertical depth, and axial position. These evaluation units include the inner wellbore evaluation unit, the middle wellbore evaluation unit, and the outer wellbore evaluation unit.

[0025] The evaluation unit in the inner wellbore is close to the horizontal wellbore and is significantly affected by bottom hole pressure differential, hydrate decomposition, and pore pressure changes. The evaluation unit in the middle wellbore is located outside the evaluation unit in the inner wellbore and mainly reflects the transmission state of pressure disturbance and effective stress changes in the reservoir skeleton. The evaluation unit in the outer wellbore is located outside the evaluation unit in the middle wellbore and is used to reflect the reservoir mechanical response after the mining disturbance expands outward.

[0026] The specific number, spatial size, and division method of the evaluation units are determined based on the target reservoir thickness, horizontal well section length, monitoring point density, and calculation accuracy requirements.

[0027] In one implementation, the evaluation unit is divided not only along the radial direction of the horizontal wellbore but also along the axial direction of the horizontal wellbore, so that each evaluation unit corresponds to a well perimeter formation region with spatial location attributes, including radial distance relative to the horizontal wellbore, position along the wellbore axis, and vertical position relative to the top and bottom interfaces of the reservoir.

[0028] By using the above division method, the formation response of different well sections, different radial regions and different vertical positions can be determined respectively, so that the formation uplift front identified later can reflect the spatial differences within the actual well section.

[0029] Furthermore, at least one of the following is obtained through downhole pressure monitoring data, temperature monitoring data, well logging interpretation data, core testing data, production dynamics inversion data, or formation response monitoring data: porosity, permeability, hydrate saturation, relative permeability of the gas phase, relative permeability of the water phase, reservoir temperature, and reservoir pressure. At least one of the following is obtained through wellbore trajectory measurement data, wellbore strain monitoring data, casing stress monitoring data, well logging interpretation data, or completion data: horizontal wellbore trajectory, wellbore curvature, casing contact pressure, and wellbore strain data. At least one of the following is obtained through wellhead flow monitoring data, bottomhole pressure monitoring data, bottomhole differential pressure data, gas production data, water production data, or production dynamics analysis data: bottomhole flowing pressure, bottomhole differential pressure, pressure drop rate, gas production, water production, and gas production contribution per unit pressure drop.

[0030] In the embodiment, a baseline state for the target horizontal well is also established in the early stage of mining. The baseline state includes initial reservoir pressure, initial reservoir temperature, initial hydrate saturation, initial bottom hole flowing pressure, initial bottom hole pressure differential, initial gas production, initial water production, initial wellbore strain state, and initial formation displacement state.

[0031] Subsequently acquired reservoir parameters, wellbore parameters, and production parameters are compared with the baseline conditions to determine changes in pore pressure, hydrate saturation, effective stress in the reservoir skeleton, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop. The baseline conditions can be determined before depressurization begins or during the stable production phase in the early stages of production.

[0032] Furthermore, pressure monitoring points arranged along the horizontal wellbore are used to obtain data on bottom hole flowing pressure and reservoir pressure changes; temperature monitoring data is used to obtain reservoir temperature changes during hydrate decomposition; and well logging interpretation data and production dynamic inversion data are used to obtain the trend of hydrate saturation changes. The spatial morphology of the horizontal wellbore is determined by wellbore trajectory data, and the wellbore curvature is determined based on the continuous wellbore trajectory changes. The casing contact pressure is determined by wellbore strain monitoring data or casing stress monitoring data. The gas production contribution per unit pressure drop is determined by wellhead gas production, water production, bottom hole flowing pressure, and bottom hole pressure difference data. The gas production contribution per unit pressure drop is used to reflect the gas production response corresponding to a unit pressure drop under the current bottom hole pressure difference conditions.

[0033] The curvature of the wellbore can be calculated from the spatial trajectory data of the horizontal wellbore axis. The spatial trajectory data can come from wellbore trajectory measurement data, well completion measurement data, or subsequent well logging retest data.

[0034] For multiple measuring points continuously distributed along the wellbore axis, the local curvature can be determined based on the spatial coordinate changes of adjacent measuring points, or the wellbore bending curvature can be calculated by using three-point fitting of circular arcs, spline curve fitting, or the rate of change of direction angle of adjacent well sections.

[0035] The casing contact pressure can be obtained by converting casing strain monitoring data, casing stress monitoring data, or formation-wellbore contact mechanical model. In one embodiment, the local stress of the casing can be determined first based on the casing strain and casing material parameters, and then the casing contact pressure can be calculated by combining the casing outer diameter, wall thickness, Poisson's ratio, and the contact state between the casing and the wellbore.

[0036] Furthermore, the formation surrounding the horizontal wellbore is divided into multiple evaluation units. These evaluation units can be divided according to radial distance or by a combination of radial distance, vertical depth, and axial position.

[0037] Then, the changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton in each evaluation unit are determined: the changes in pore pressure are determined by pressure monitoring data, seepage calculation results, or formation response monitoring data; the changes in hydrate saturation are determined by hydrate decomposition state, production dynamics inversion results, well logging interpretation results, or reservoir response data; and the changes in effective stress of the reservoir skeleton are determined by pore pressure changes, formation mechanical parameters, and reservoir deformation response.

[0038] The uplift driving force of each evaluation unit is obtained by integrating the changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton.

[0039] For evaluation units close to horizontal wellbores, changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton are all used as the basis for determining the uplift driving force; for evaluation units far from horizontal wellbores, the uplift driving force is determined based on changes in pore pressure, changes in effective stress of the reservoir skeleton, or a combination thereof.

[0040] The fusion calculation is not limited to a single formula, but can be achieved by weighted fusion calibrated by the target reservoir, lookup table mapping, or empirical correction relationship.

[0041] In one specific implementation, the weighted fusion of the bulge driving quantity includes two steps: dimension unification and weight fusion.

[0042] First, using the baseline conditions established at the initial stage of mining as a reference, the pore pressure variation in each evaluation unit was determined. Change in hydrate saturation and the effective stress variation of the reservoir skeleton The three types of changes are then converted into dimensionless parameters. , and These are the normalized values ​​corresponding to the changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton, respectively.

[0043] In this embodiment, the dimensionless parameter is preferably obtained using the range standardization method, as shown in the following formula:

[0044]

[0045]

[0046] In the formula, and These represent the maximum and minimum values ​​of pore pressure change for the corresponding evaluation unit within the most recent sampling periods. , , and Determine in the same way.

[0047] If the target well already has a clear design safety limit or long-term historical operating condition quantile, the benchmark value ratio or safety limit normalization method can also be used in alternative implementation methods. However, in this embodiment, range standardization is the preferred implementation path.

[0048] Subsequently, the bulge driving amount of the j-th evaluation unit is calculated according to the following formula. :

[0049] in, , , Let be the fusion weight of the j-th evaluation unit, and satisfy the following formula:

[0050] For the evaluation unit within the well perimeter area , , The preferred values ​​are 0.30, 0.40, and 0.30; for the evaluation unit in the well perimeter area, , , The preferred values ​​are 0.32, 0.33, and 0.35; for the evaluation unit in the outer area around the well, , , The preferred values ​​are 0.28, 0.22, and 0.50. These weights represent preferred embodiments of typical weakly cemented natural gas hydrate reservoirs and allow for minor adjustments based on core mechanics tests, well logging interpretation results, or monitoring data from the pilot production phase.

[0051] In one implementation, the calculation of uplift driving force can be further corrected by considering the location of the evaluation unit. This location correction is used to characterize the impact of the evaluation unit's spatial orientation relative to the horizontal wellbore, the distance between the top and bottom interfaces of the reservoir, and the axial production intensity on the uplift driving force. For evaluation units located above horizontal wellbores, the contribution of effective stress changes in the reservoir skeleton and vertical displacement changes to the uplift driving force can be increased; for evaluation units located laterally to horizontal wellbores, the contribution of pore pressure changes and seepage disturbance states to the uplift driving force can be increased; for evaluation units extending axially along the horizontal wellbore and close to high-yield gas well sections, the influence of production parameter changes on the uplift driving force can be incorporated into the fusion calculation process.

[0052] In this embodiment, position correction can be achieved through a position correction coefficient. The corrected bulge driving amount is shown in the following formula:

[0053] The position correction coefficient Determined based on the spatial location of the evaluation unit: For evaluation units located above and close to the horizontal wellbore, The preferred value is 1.15; for evaluation units located laterally in horizontal wellbores, The preferred value is 1.00; for evaluation units that are far from horizontal wellbores and experience relatively weak mining disturbance, The preferred value is 0.90. The above value is used to provide a reproducible embodiment, based on the spatial response differences of the evaluation unit above the horizontal wellbore, which is more affected by vertical displacement and effective stress redistribution; the lateral evaluation unit, which mainly reflects seepage disturbance; and the far-field evaluation unit, which is less affected by mining disturbance.

[0054] In another implementation, the acquired data undergoes time window processing. This time window processing includes smoothing reservoir parameters, wellbore parameters, and production parameters within consecutive time steps, removing abnormal fluctuations, and determining trends. By using time window processing, the impact of single-monitor fluctuations on uplift driving forces can be reduced, making the uplift driving forces more suitable for identifying formation uplift fronts and controlling bottomhole differential pressure.

[0055] S2. Identify the formation uplift front based on the uplift driving amount and the corresponding vertical displacement change trend of the adjacent evaluation units.

[0056] In this embodiment, the location of the formation uplift front is determined based on whether the changes in uplift driving amount and vertical displacement between adjacent evaluation units meet the preset front identification conditions.

[0057] The preset leading edge identification conditions include at least one of the following: bulge driving amount difference condition, vertical displacement change trend condition, and continuous time step stability condition.

[0058] When the difference in uplift driving force between adjacent evaluation units in the stratum reaches the set condition, and the vertical displacement change trend at the corresponding location shows a change from a stable state to an active state, the boundary location that meets the condition is determined as the uplift front of the stratum.

[0059] In one specific implementation, the bulge driving amount difference condition is defined as the difference in bulge driving amount between two adjacent evaluation units. Greater than the preset difference threshold Or, the relative difference in the amount of bulge driving force satisfies the following formula:

[0060] in, The average value of the bulge driving amount of two adjacent evaluation units is uniformly taken, and the preset difference threshold is used. It can be calibrated by the background fluctuations during the stable phase of trial production: A continuous time window in which the wellbore integrity is stable is selected as the benchmark window, and the average value of the difference in uplift driving amount between adjacent evaluation units within this benchmark window is calculated. and standard deviation And set according to the following formula :

[0061] The vertical displacement change trend condition is defined as the rate of change of the vertical displacement of the corresponding evaluation unit changing from a state close to zero or decreasing to a state of continuous increase, and exceeding a preset displacement change rate threshold. , It can be determined based on the average and standard deviation of the rate of change of vertical displacement within the reference window, for example, by setting it according to the following formula:

[0062] The vertical displacement variation trend can be determined through wellbore distributed fiber optic strain monitoring data, wellbore trajectory re-measurement data, formation response inversion data, or numerical update results. Distributed fiber optic strain monitoring data reflects the strain change at the wellbore-formation contact interface, while formation response inversion data or numerical update results map the deformation response of a limited number of monitoring points to the corresponding wellbore evaluation units. The continuous time step stability condition is defined as the above-mentioned uplift driving difference condition and vertical displacement variation trend condition within a continuous time step. It is valid within each sampling time step, among which It is an integer greater than or equal to 2, preferably 3 to 5.

[0063] In one implementation, the uplift driving force and vertical displacement variation trends of each evaluation unit are tracked over multiple consecutive time steps. When the uplift driving force variation between a certain evaluation unit and its adjacent evaluation units continuously meets the preset leading edge identification conditions, and the vertical displacement variation trend corresponding to that evaluation unit remains consistent over consecutive time steps, the location is identified as the formation uplift leading edge. By using continuous time step determination, the impact of single monitoring fluctuations on the leading edge identification results can be reduced, making the leading edge distance, leading edge advance speed, and leading edge influence length more suitable for bottomhole differential pressure control.

[0064] In one implementation, the influence range of the formation uplift front is also determined based on the continuity of the formation uplift front at different axial positions. When multiple adjacent axial evaluation units meet the preset front identification conditions, the well sections where these evaluation units are located are identified as well sections affected by the formation uplift front. If only a single evaluation unit meets the identification conditions in a short period of time, and its adjacent evaluation units do not show the same trend, then the position is not temporarily regarded as a stable formation uplift front, but is verified in subsequent time steps.

[0065] S3. Based on the identified formation uplift front, calculate the front advance velocity of the formation uplift front and the front influence length along the axial direction of the horizontal well.

[0066] The leading edge distance is the spatial distance between the formation uplift leading edge and the horizontal wellbore. The leading edge advance speed is determined based on the change of the leading edge distance within a continuous time step and is used to characterize the advance speed of the formation uplift leading edge. The leading edge influence length is the extension range of the formation uplift leading edge along the axial direction of the horizontal wellbore and is used to characterize the length of the well section influenced by the formation uplift leading edge.

[0067] In one specific implementation, the leading edge propulsion velocity can be obtained by the difference in leading edge distance between adjacent sampling times, as shown in the following formula:

[0068] in, (k) represents the leading edge distance at the k-th sampling time. This refers to the k-th sampling time. To reduce the impact of fluctuations in a single monitoring session, continuous sampling can be performed. The leading edge propagation velocity at each sampling time is processed by moving average or median filtering, where It is an integer greater than or equal to 3.

[0069] The leading edge influence length can be obtained by statistically analyzing the lengths of consecutive evaluation units that meet the preset leading edge identification conditions along the axial direction of the horizontal wellbore. When multiple adjacent axial evaluation units all meet the preset leading edge identification conditions, their corresponding axial lengths are summed as the leading edge influence length.

[0070] The dimensions of the leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are uniformly processed so that parameters of different dimensions can participate in the construction of the same control index.

[0071] Based on the priority of wellbore safety and the priority of gas production efficiency, the parameters after dimension unification are integrated to obtain the wellbore safety and gas production coordinated control index. The leading edge advance speed is used to reflect the dynamic evolution of formation uplift deformation, the wellbore curvature is used to reflect the geometric deformation of the horizontal wellbore, the casing contact pressure is used to reflect the stress state of the casing, and the gas production contribution per unit pressure drop is used to reflect the gas production efficiency during the depressurization process.

[0072] S4. Based on the aforementioned leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop, construct a collaborative control index.

[0073] In the embodiment, the leading edge advance velocity, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are converted into dimensionless parameters. , , and In this embodiment, , and The range standardization method is preferred, with the maximum and minimum values ​​of the standardized range taken from the statistical range of the stable trial production stage and the current rolling monitoring window. A higher gas production contribution per unit pressure drop generally indicates better gas production efficiency; therefore, a 1- This is an inefficient gas production factor.

[0074] The wellbore safety gas production synergistic control index is calculated using the following formula. :

[0075] in, , , , To integrate the weights and satisfy the following formula:

[0076] As a preferred embodiment, when the wellbore integrity priority is high... , , , The values ​​are taken as 0.25, 0.25, 0.30, and 0.20 respectively; when the wellbore safety condition is stable and the gas production efficiency has a high priority, , , , Take values ​​of 0.20, 0.20, 0.25, and 0.35 respectively.

[0077] In one implementation, when the wellbore integrity requirement is high or the wellbore stress state is close to the safety boundary, the influence weights of the leading edge advance speed, wellbore curvature, and casing contact pressure in the wellbore safety gas production synergistic control index are increased; when the wellbore safety risk is low and the gas production demand is high, the influence weight of the gas production contribution per unit pressure drop in the wellbore safety gas production synergistic control index is increased. The above weight adjustments are determined based on the target reservoir mechanical conditions, wellbore integrity requirements, production system requirements, and field operation strategies.

[0078] In one implementation, the bottom hole pressure differential control range is also determined by considering the leading edge influence length: When the wellbore safety gas production coordination control index increases, but the influence length of the leading edge only covers a local section of the horizontal wellbore, priority is given to implementing local pressure stabilization or segmented production switching for the affected section; when the influence length of the leading edge covers most of the horizontal wellbore, the overall well pressure reduction rate or bottom hole pressure differential is adjusted. Thus, the bottom hole pressure differential control action corresponds to the spatial influence range of the formation uplift leading edge.

[0079] S5. In response to the coordinated control index reaching the preset control level, the control range of the bottom hole pressure difference of the horizontal well is determined based on the leading edge influence length, and a graded control action corresponding to the control level is executed, wherein the control range includes a local well section or the entire well.

[0080] The control level is determined based on the wellbore safety gas production coordination control index and the preset control level conditions. The control level can be divided into multiple levels according to the target reservoir mechanical conditions, wellbore integrity requirements and production system requirements.

[0081] According to the control level, corresponding graded control actions are executed. The graded control actions include at least one of maintaining the current bottom hole pressure difference, reducing the pressure reduction rate, step-by-step back pressure, local pressure stabilization, or segmented production switching.

[0082] In other embodiments, the graded control action can also be used in conjunction with reservoir temperature regulation measures, which are only used to assist in adjusting the local reservoir decomposition state.

[0083] In one embodiment, the wellbore safety gas production coordinated control index is a dimensionless index, which is determined based on a first control level threshold and a second control level threshold. When the wellbore safety gas production coordinated control index is less than or equal to the first control level threshold, it is determined to be a lower risk level; when the wellbore safety gas production coordinated control index is greater than the first control level threshold and less than or equal to the second control level threshold, it is determined to be a higher risk level; and when the wellbore safety gas production coordinated control index is greater than the second control level threshold, it is determined to be an even higher risk level.

[0084] The first and second control level thresholds are determined by the background fluctuations of indicators during the stable trial production phase: the stable trial production phase is selected as the benchmark window, and the average value of the wellbore safety gas production coordinated control indicators within this benchmark window is calculated. and standard deviation And determine it according to the following formula:

[0085]

[0086] When there is already a safety margin for casing contact pressure or a safety limit for wellbore curvature on site, the above thresholds and the corresponding index values ​​can be checked to ensure that the control level matches the wellbore integrity requirements.

[0087] In one implementation, when the wellbore safety gas production coordination control index meets the low-risk level conditions, the current bottom hole pressure differential or the current depressurization rate is maintained; when the wellbore safety gas production coordination control index meets the high-risk level conditions, the depressurization rate is reduced, a stepped back pressure is implemented, or local pressure stabilization is performed to reduce the gradient of bottom hole pressure differential changes and delay the advance of the formation uplift front; when the wellbore safety gas production coordination control index meets the higher-risk level conditions, local pressure stabilization or segmented production switching is implemented in the well section affected by the formation uplift front, and production is maintained in the well section with low wellbore safety risk.

[0088] In one implementation, when performing control actions, the safety status of the wellbore in the current well section is determined first. When the front edge of the formation uplift approaches the horizontal wellbore, the front edge advance speed increases, the curvature of the wellbore increases, or the casing contact pressure increases, the pressure reduction rate, step-by-step back pressure, or local pressure stabilization are prioritized.

[0089] When the gas production contribution per unit pressure drop decreases but the wellbore safety risk remains low, maintain the current bottom hole pressure differential or reduce the extent of further pressure differential increase; when a certain horizontal well section is significantly affected by the formation uplift front, while other well sections remain in a low-risk state, implement segmented production switching to reduce the production intensity or suspend production in the affected well section, while maintaining production in other well sections.

[0090] After the tiered control actions are executed, the reservoir parameters, wellbore parameters, and production parameters are updated, and the calculations are re-executed. This creates a continuous closed-loop control system during the depressurization production of natural gas hydrate horizontal wells, allowing the bottomhole pressure differential control actions to adjust in response to changes in reservoir, wellbore, and production responses.

[0091] In one specific embodiment, the target natural gas hydrate horizontal well is located in a weakly cemented porous media reservoir in the ocean. The horizontal wellbore penetrates the target hydrate reservoir, and the porosity, hydrate saturation, reservoir pressure, and reservoir temperature of the reservoir are determined using well logging interpretation data, core testing data, and production dynamics inversion data. During the initial stage of production, a depressurization method is used for production, and bottom hole pressure, bottom hole differential pressure, gas production, water production, wellbore strain, and formation displacement response data are acquired according to a preset sampling cycle.

[0092] In this embodiment, the formation around the horizontal wellbore is divided into an inner wellbore evaluation unit, a middle wellbore evaluation unit, and an outer wellbore evaluation unit. The pore pressure change of each evaluation unit is determined based on pressure monitoring data, the hydrate saturation change is determined based on production dynamics inversion results, and the effective stress change of the reservoir skeleton is determined based on pore pressure change and formation deformation response. The above parameters are fused and calculated to obtain the uplift driving amount of each evaluation unit.

[0093] After receiving the uplift driving force from each evaluation unit, the changes in uplift driving force between adjacent evaluation units are compared, and the vertical displacement trend is used to determine whether the preset leading edge identification conditions are met. If there is a significant change in uplift driving force between the evaluation units in the inner well perimeter and the evaluation units in the middle well perimeter, and the vertical displacement at the corresponding location changes from a stable change to a continuous increase, then the boundary location is determined as the formation uplift leading edge. Subsequently, the leading edge distance, leading edge advance velocity, and leading edge influence length are determined.

[0094] The dimensions of leading-edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are standardized. Based on wellbore safety priority and gas production efficiency priority, the roles of each parameter in the wellbore safety and gas production coordinated control index are determined, generating the wellbore safety and gas production coordinated control index. The current operating condition is determined to be at the corresponding control level based on the wellbore safety and gas production coordinated control index and preset control level conditions.

[0095] When the current operating condition is determined to correspond to a high risk level, a control command to reduce the rate of pressure reduction is generated. The bottom hole differential pressure regulating device reduces the rate of pressure reduction per unit time according to the control command. After the control action is executed, the data is updated, and the uplift drive, formation uplift front, and wellbore safety gas production coordinated control index are recalculated. If the updated wellbore safety gas production coordinated control index is reduced to a lower risk level range, the new bottom hole differential pressure and pressure reduction rate are maintained; if the updated wellbore safety gas production coordinated control index is still at a high risk level, the step-wise backpressure or local pressure stabilization continues to be implemented.

[0096] In another embodiment, the target horizontal wellbore extends along multiple high hydrate saturation sections within the reservoir. Due to different reservoir conditions in different well sections, the advance state of the formation uplift front at different axial positions is different. It is determined that the front influence length of a certain well section is relatively long, and the casing contact pressure of the corresponding well section is increased.

[0097] At this time, instead of uniformly reducing pressure across the entire well, a segmented production switch is implemented for the affected well sections, reducing or suspending production in the affected sections while maintaining production in well sections with lower wellbore safety risks.

[0098] In this way, the bottom hole pressure differential control action corresponds to the differentiated risk status of the well section.

[0099] In another embodiment, the wellbore safety gas production coordination control index shows that the wellbore safety risk is at a low level, but the gas production contribution per unit pressure drop decreases, indicating that continuing to increase the bottom hole pressure difference has a limited effect on increasing gas production.

[0100] At this point, maintain the current bottom hole pressure differential or implement local pressure stabilization, rather than continuing to increase the pressure reduction.

[0101] This approach avoids simply pursuing gas production and continuously increasing the bottom hole pressure differential, thus ensuring that the bottom hole pressure differential control matches the gas production efficiency.

[0102] In another embodiment, during the mining process, the advance rate of the formation uplift front in a certain well section is low, but the casing contact pressure continues to rise.

[0103] At this point, it is determined that the stress state of the wellbore in this section has changed. Even if the formation uplift front does not advance rapidly, local pressure stabilization or stepped back pressure is still implemented according to the wellbore safety gas production coordination control index.

[0104] This embodiment illustrates that the control basis of the present invention is not limited to a single reservoir front parameter, but simultaneously considers wellbore curvature, casing contact pressure and gas production contribution per unit pressure drop.

[0105] In another embodiment, the gas production contribution per unit pressure drop is high in the early stage of production, and the wellbore curvature and casing contact pressure are both at a low level, maintaining the current bottom hole pressure difference or continuing to reduce pressure according to the preset production system.

[0106] When the subsequent unit pressure drop in gas production decreases while the forward advance speed increases, it is determined that the gas production benefit of continuing to increase the bottom hole pressure difference is reduced and the wellbore safety risk is increased. Therefore, the pressure reduction rate or step-back pressure is implemented.

[0107] This embodiment illustrates that the present invention can adjust the production system in conjunction with changes in gas production efficiency and wellbore safety risks.

[0108] In another embodiment, the target reservoir is highly heterogeneous, with significant differences in porosity, permeability, and hydrate saturation in different sections along the horizontal wellbore.

[0109] Reservoir parameters for different well sections are obtained based on well logging interpretation data and production dynamics inversion data; the formation around the horizontal wellbore is divided into multiple evaluation areas according to the differences in well sections; the formation uplift front corresponding to different well sections is identified; and production maintenance, pressure reduction rate reduction, local pressure stabilization, or segmented production switching are implemented according to the coordinated control indicators of different well sections.

[0110] This embodiment illustrates that the present invention can be applied to the segmented regulation of heterogeneous hydrate reservoirs.

[0111] To illustrate the operational effectiveness of this invention under simulated conditions, a comparative example and a control example were set up. The example used the wellbore safety gas production synergistic control method of this invention, while the control example used a constant pressure reduction rate control method. Both examples used the same initial reservoir parameters, wellbore parameters, and production parameters as inputs. The difference was that the example adjusted the bottom hole pressure differential based on the formation uplift front and the wellbore safety gas production synergistic control index, while the control example did not adjust the bottom hole pressure differential based on the formation uplift front.

[0112] In the example operation, during the extraction process, the advance of the formation uplift front towards the outside of the horizontal wellbore was detected, and the wellbore curvature and casing contact pressure were detected to be increasing. Based on this, a wellbore safety gas production coordination control index was generated. After determining that the index met the conditions for a higher risk level, a control action to reduce the pressure drop rate was executed, and the front advance speed, casing contact pressure, and gas production contribution per unit pressure drop were continuously updated in subsequent sampling cycles.

[0113] In the comparative operating condition, the bottom hole pressure differential continues to increase according to the original pressure reduction rate, without being adjusted according to the advancement state of the formation uplift front.

[0114] The key parameters under simulated operating conditions are compared in Table 1 below.

[0115]

[0116] Table 1. Comparison of key parameters under simulated operating conditions As can be seen from the above comparison of simulated working conditions, in the example working condition, by identifying the formation uplift front and implementing graded control according to the wellbore safety gas production coordination control index, the front advance speed, wellbore curvature and casing contact pressure are kept at a relatively low level, while the gas production contribution per unit pressure drop is kept at a high level. In the comparative working condition, since the bottom hole pressure difference is not adjusted according to the formation uplift front, the wellbore safety risk parameters continue to rise with the pressure reduction process.

[0117] This comparison demonstrates that the present invention can convert the formation uplift front identification results into bottom hole pressure differential control actions, which is beneficial to achieving a dynamic balance between wellbore integrity and gas production efficiency.

[0118] The above simulated operating conditions are only used to illustrate the control logic of the present invention. In actual applications, the specific values ​​of the leading edge advance speed, wellbore curvature, casing contact pressure, gas production contribution per unit pressure drop, and wellbore safety gas production synergistic control indicators are determined according to the geological conditions of the target reservoir, the horizontal well completion structure, the accuracy of monitoring data, and the requirements of the production system. The correspondence between the number of control levels, control level conditions, and graded control actions is also adjusted according to the wellbore integrity requirements and gas production targets.

[0119] This invention is applicable to bottom hole pressure differential control during the depressurization process of horizontal wells for natural gas hydrate production. It is particularly suitable for production scenarios in weakly cemented or non-diagenetic porous media reservoirs where there are risks of formation uplift, wellbore bending, casing pressure, or wellbore instability. In the production of offshore natural gas hydrate horizontal wells, multi-branch horizontal wells, and heterogeneous hydrate reservoirs, this invention can adjust the bottom hole pressure differential control action according to the reservoir response, wellbore response, and production response.

[0120] It can be seen that the present invention does not only use gas production or bottom hole pressure as the basis for production control, but also incorporates the reservoir deformation front, wellbore stress state and gas production contribution per unit pressure drop into the control judgment, and further determines the bottom hole pressure differential control range of local well sections or the whole well based on the front influence length of the formation uplift front, so that the bottom hole pressure differential adjustment is matched with the wellbore safety state, gas production efficiency state and front influence range.

[0121] It should be noted that the specific implementation methods described above, such as image processing, numerical simulation, and the construction and training of machine learning models, can all be accomplished by the processor by calling the corresponding computer program instructions stored in memory. Those skilled in the art can implement the above functions using algorithms and tools known in the prior art, according to actual needs.

[0122] Please see Figure 2 In this embodiment, to efficiently execute the wellbore safety gas production coordination and control method for horizontal well depressurization mining provided by this invention, the present invention also provides a wellbore safety gas production coordination and control system for horizontal well depressurization mining, comprising: an input device 1, an output device 2, a processor 3, and a memory 4. The input device 1, output device 2, processor 3, and memory 4 are interconnected. The memory 4 stores program instructions used to execute the steps of the wellbore safety gas production coordination and control method for horizontal well depressurization mining. The wellbore safety gas production coordination and control system for horizontal well depressurization mining of this invention has a compact structure and stable performance, and can stably execute the wellbore safety gas production coordination and control method for horizontal well depressurization mining of this invention, further improving the overall applicability and practical application capability of this invention.

[0123] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention, and they should all be covered within the scope of the present invention.

Claims

1. A method for coordinated control of wellbore safety and gas production in horizontal well depressurization production, characterized in that, Includes the following steps: Obtain reservoir parameters, wellbore parameters, and production parameters of the production area of ​​a horizontal well for natural gas hydrates; and determine the uplift driving amount of the wellbore evaluation unit of the horizontal well based on the reservoir parameters, wellbore parameters, and production parameters. Based on the uplift driving amount and the corresponding vertical displacement change trend of the adjacent evaluation units, the uplift front is identified; Based on the identified formation uplift front, the forward advance velocity of the formation uplift front and the forward influence length along the axial direction of the horizontal well are calculated; Based on the aforementioned leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop, a collaborative control index is constructed. In response to the coordinated control index reaching a preset control level, the control range of the bottom hole pressure difference of the horizontal well is determined based on the leading edge influence length, and a graded control action corresponding to the control level is executed, wherein the control range includes a local well section or the entire well.

2. The wellbore safety gas production coordinated control method for horizontal well depressurization production according to claim 1, characterized in that, The well perimeter evaluation unit is obtained by dividing the formation around the horizontal well based on its spatial location, and the evaluation unit includes at least multiple evaluation units with different radial distances. Determining the uplift drive of the wellbore evaluation unit of the horizontal well includes: Determine the changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton for each of the evaluation units. The uplift driving amount of each evaluation unit is obtained by weighting and fusing the changes in pore pressure, hydrate saturation, and effective stress of the reservoir skeleton.

3. The wellbore safety gas production coordinated control method for horizontal well depressurization production according to claim 2, characterized in that, The plurality of evaluation units include at least an inner well perimeter evaluation unit, a middle well perimeter evaluation unit, and an outer well perimeter evaluation unit; For the well perimeter evaluation unit, the weights of the pore pressure change, hydrate saturation change, and reservoir skeleton effective stress change during weighted fusion are 0.30, 0.40, and 0.30, respectively. For the well perimeter zone evaluation unit, the weights are 0.32, 0.33, and 0.35, respectively; For the evaluation unit of the outer area around the well, the weights are 0.28, 0.22 and 0.50, respectively.

4. The wellbore safety gas production coordinated control method for horizontal well depressurization production according to claim 2, characterized in that, After obtaining the uplift driving force of each evaluation unit through weighted fusion, the following is also included: The uplift driving amount is corrected by a position correction coefficient based on the spatial orientation of the evaluation unit relative to the horizontal wellbore.

5. The method for coordinated control of wellbore safety and gas production in horizontal well depressurization production according to claim 1, characterized in that, The step of identifying the formation uplift front based on the uplift driving amount and corresponding vertical displacement change trend of adjacent evaluation units includes: The boundary of the area that meets the conditions is determined as the uplift front only when the difference in the uplift driving amount between adjacent evaluation units is greater than the preset difference threshold, and the vertical displacement change trend at the corresponding location meets the preset displacement change rate threshold, and this condition is met for N consecutive sampling time steps. Here, N is an integer greater than or equal to 2.

6. The method for coordinated control of wellbore safety and gas production in horizontal well depressurization production according to claim 1, characterized in that, The calculation of the advance velocity of the formation uplift front and the length of its influence along the axial direction of the horizontal well, based on the identified formation uplift front, includes: The advance rate of the formation uplift front relative to the horizontal well is determined based on the change in the spatial distance between the formation uplift front and the horizontal well at continuous sampling times; The length of the continuous evaluation unit that meets the preset leading edge identification conditions along the axial direction of the horizontal well is counted to determine the leading edge influence length.

7. The method for coordinated control of wellbore safety and gas production in horizontal well depressurization production according to claim 1, characterized in that, The aforementioned collaborative control indicators are constructed based on the leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop, including: The aforementioned leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are converted into dimensionless parameters. The dimensionless parameters are weighted and summed to obtain the coordinated control index, wherein, in order to characterize insufficient gas production efficiency, the weight of the gas production contribution per unit pressure drop is given a negative correlation. When wellbore integrity is given a high priority, the weights corresponding to the leading edge advance speed, wellbore curvature, casing contact pressure, and gas production contribution per unit pressure drop are 0.25, 0.25, 0.30, and 0.20, respectively. When the wellbore safety status is stable and the gas production efficiency has a high priority, the weights are 0.20, 0.20, 0.25 and 0.35, respectively.

8. The wellbore safety gas production coordinated control method for horizontal well depressurization production according to claim 1, characterized in that, The coordinated regulation index is a dimensionless index, and the preset regulation level is divided at least according to the first regulation level threshold and the second regulation level threshold. The step of responding to the coordinated control indicator reaching a preset control level and executing corresponding graded control actions includes: When the coordinated control index is less than or equal to the first control level threshold, it corresponds to a lower risk level, and the current bottom hole pressure differential or depressurization rate is maintained. When the coordinated control index is greater than the first control level threshold and less than or equal to the second control level threshold, it corresponds to a higher risk level, and measures such as reducing the voltage reduction rate, step-wise back pressure, or local voltage stabilization are implemented. When the coordinated control indicator is greater than the second control level threshold, a higher risk level is indicated, and segmented production switching is executed.

9. The method for coordinated control of wellbore safety and gas production in horizontal well depressurization production according to claim 1, characterized in that, In response to the coordinated control index reaching a preset control level, the control range for the bottom hole pressure differential of the horizontal well is determined based on the leading edge influence length, and a graded control action corresponding to the control level is executed, including: When it is determined that bottom hole pressure differential adjustment needs to be performed and the leading edge influence length only covers a portion of the horizontal well section, local pressure stabilization or segmented production switching is performed on the portion of the well section. When the length of the front edge influence covers the entire section of the horizontal well, the depressurization rate or bottom hole pressure differential of the entire well is adjusted.

10. A wellbore safety gas production coordinated control system for horizontal well depressurization production, characterized in that, The wellbore safety gas production coordination and control system for horizontal well depressurization mining includes: an input device, an output device, a processor, and a memory. The input device, output device, processor, and memory are interconnected. The memory stores program instructions, which are used to execute the wellbore safety gas production coordination and control method for horizontal well depressurization mining according to any one of claims 1-9.

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