Extension limit prediction method and device for extended reach well, storage medium and electronic equipment

Abstract

The invention discloses a method and device for predicting the extension limit of an extended reach well, and the method comprises the steps: building an attenuation function of stratum mechanics parameters along with exposure time through a rock mechanics experiment, and updating the rock strength parameters such as cohesion and internal friction angle in real time; a column coordinate system force-chemical coupling model is adopted to quantify the collapse pressure increment, and the well diameter expansion rate and the well hole state are dynamically determined in combination with the drilling fluid density; a rock debris two-layer migration model and an annular flow channel dynamic database are constructed, equivalent circulation density is calculated through iteration of a two-phase flow model, and a finite element method is used for analyzing dynamic laws of friction torque and axial force of the drill string. And the well depth increment serves as an optimization variable, the well wall stable state, the ECD, the friction torque and the axial force change are synchronously solved, and when any parameter reaches a critical value, the dynamic extension limit is output. Through a time sequence dynamic coupling mechanism, the extended reach well extension limit prediction precision and construction safety are improved, and the method is suitable for complex stratum drilling engineering design.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of drilling engineering of oil and gas resources, and particularly relates to a method and device for predicting the extension limit of a extended reach well, a storage medium and an electronic device. BACKGROUND

[0002] Under the background of the increasingly exhausted conventional oil and gas resources, the efficient development of complex oil and gas reservoirs (including deep-sea basins, tight sandstone and shale formations, etc.) has become an important direction of energy strategy. As one of the core technologies for the development of complex oil and gas, the extended reach well has become an engineering and technical direction for oil companies to focus on development, because of its significant technical advantages: the extension distance of the horizontal section is more than 3-5 times that of the conventional directional well, the reservoir contact area is increased by more than 4 times, and the single well production capacity is doubled.

[0003] The traditional extension limit prediction theory decouples the constraint conditions into three independent dimensions: the mechanical extension limit (limited by the pipe string strength and the dynamic system), the open hole extension limit (subjected to the formation fracture pressure window) and the hydraulic extension limit (controlled by the pumping system parameters). The existing prediction model generally uses a static analysis framework, which has two key defects: first, the dynamic coupling mechanism of multiple constraint conditions is not established, resulting in significant deviation in the prediction results of each limit value; second, the time effect characteristics of the wellbore state are ignored, especially the time-varying law of the wellbore stability caused by the long-time contact between the drilling fluid and the formation. This directly leads to insufficient prediction accuracy of the existing model, which is difficult to meet the engineering needs of modern intelligent drilling.

[0004] More specifically, the traditional method has a major theoretical defect in the calculation of the open hole extension limit: the initial formation parameters are used as constant inputs, and the rock strength degradation effect caused by the long-time contact between the drilling fluid and the formation is not considered. This static assumption significantly underestimates the wellbore instability risk, resulting in frequent sudden well collapse accidents in actual drilling operations. In addition, the existing annular pressure loss calculation model regards the wellbore shape as an ideal geometric body, and fails to effectively correlate the wellbore instability process with the dynamic evolution of the annular flow channel geometry, resulting in a deviation of 15%-20% between the predicted and measured equivalent circulating densities (ECD). SUMMARY

[0005] In view of the existing technical problems, the present application provides a method and device for predicting the extension limit of an extended reach well, a storage medium and an electronic device, which aims to overcome the problems in the above-mentioned technology.

[0006] To achieve the above-mentioned purpose, the present application provides the following technical solutions: The method for predicting the extension limit of an extended reach well comprises the following steps: S1. Obtain the decay function of the formation collapse pressure with the exposure time of the wellbore through rock mechanics experiments, establish a rock strength degradation coefficient matrix based on time series, and update the rock strength parameters in real time; S2. Adopting the force-chemical coupling model under the cylindrical coordinate system, quantifying the collapse pressure increment ΔP(t) of different well deviation angle sections after drilling time t, and establishing the time-varying law of wellbore stability; S3. According to the real-time drilling fluid density data, combining the dynamic changes of collapse pressure and fracture pressure, determining the change of wellbore state with the drilling time of wellbore, and obtaining the hole enlargement rate and the collapse volume at different depths; S4. Establishing a two-layer dynamic migration model of cuttings in extended reach wells, considering the dynamic changes of hole enlargement rate and wellbore collapse volume, and calculating the change of cuttings bed thickness under the condition of real-time ROP; S5. Constructing a dynamic database of annular flow channel geometric parameters under non-ideal wellbore morphology, introducing the hole enlargement rate η as the correction factor of flow channel cross-sectional area, and realizing the dynamic iterative calculation of ECD value through the annular two-phase flow ECD prediction model; S6. Analyzing the change law of pipe column friction torque with well depth under non-ideal wellbore morphology by numerical simulation method, and determining the dynamic change law of friction torque; S7. Taking the well depth increment ΔL as the optimization variable, synchronously solving the wellbore stability state, drilling fluid ECD and pipe column friction torque within the time step Δt, judging whether the drilling fluid ECD and pipe column friction torque and axial force reach the critical value under the condition of real-time wellbore stability state, and outputting the dynamic extension limit if either of them reaches the critical value.

[0007] Optionally, in step S1, the rock strength parameters include cohesion C(t) and internal friction angle φ(t), and the decay function is: wherein, , C0 and φ0 are the initial cohesion and internal friction angle of the formation, , C1 and φ1 are the deterioration coefficients fitted by experiments, t is the drilling time of wellbore.

[0008] Optionally, in step S2, the collapse pressure increment ΔP(t) is calculated by Mohr-Coulomb criterion, and the force-chemical coupling model is established based on the cylindrical coordinate system to calculate the collapse pressure increment after the drilling fluid contacts the formation for a time ΔT under the conditions of real-time well deviation angle and azimuth angle: According to the real-time drilling fluid density determine the change of pore pressure around the wellbore after the drilling fluid invades the formation, and obtain the change amount of formation leakage pressure after the drilling fluid contacts the formation for a time ΔT: wherein, is the change of the pore pressure around the borehole with time; According to the initial collapse pressure and the lost circulation pressure of the formation and the change of the collapse pressure and the lost circulation pressure of the borehole after being drilled under the influence of the drilling fluid, the real-time values of the collapse pressure and the lost circulation pressure are obtained: wherein, , are the initial collapse pressure and the lost circulation pressure of the borehole after being drilled.

[0009] Optionally, in step S3, the hole enlargement rate is generated in combination with the dynamic change of the drilling fluid density and the borehole collapse pressure with the change of the well depth and time: The borehole state is determined by comparing the drilling fluid density with the collapse pressure : If , the borehole wall is stable, the hole enlargement rate is 0, and the volume of the cuttings in the borehole is only related to the mechanical drilling speed; If , the borehole wall collapses, the hole enlargement rate is , and the volume of the cuttings in the borehole is related to the hole enlargement rate and the mechanical drilling speed, wherein, ROP is the mechanical drilling speed, V c is the volume of the cuttings in the borehole.

[0010] Optionally, in step S4, a two-layer dynamic cuttings transport model is established, the hole enlargement rate is taken as a correction factor of the annular cross-sectional area, and the following is obtained: wherein, is the drill bit radius, is the outer diameter of the drill pipe.

[0011] Optionally, in step S5, the annular equivalent density ECD(t) is calculated through a two-phase flow model, and the expression is as follows: wherein, is the annular cross-sectional area, , is the drilling fluid mobility coefficient, is the drilling fluid displacement, H c is the thickness of the cuttings bed.

[0012] Optionally, in step S6, the drill pipe string friction torque and axial force are solved through the finite element method, and the expression is as follows: wherein, is a friction coefficient related to the state of the borehole, is a contact normal stress varying with the depth of the well, is a deviation angle varying with the depth of the well, is a length of the well section.

[0013] An apparatus for implementing the method of any one of the preceding, comprising: a first processing unit for determining a change rule of the wellbore collapse pressure with time according to experimental data; a second processing unit for determining a change rule of the wellbore fracture pressure with time according to the real-time drilling fluid density; a third processing unit for determining the hole enlargement rate and the real-time state of the borehole according to the real-time drilling fluid density and the collapse pressure; a fourth processing unit for calculating the drilling fluid equivalent circulating density (ECD) according to the hole enlargement rate and the annular two-phase flow model; a fifth processing unit for determining the peak value of the drill string torque and the minimum value of the wellhead axial force by using the finite element method; a sixth processing unit for determining the dynamic extension limit of the extended reach well by comparing whether the ECD and the peak value of the drill string torque reach the critical value and whether the wellhead axial force is 0.

[0014] A computer storage medium having a computer program stored thereon, the program being executed by a processor to implement the steps of the method of any one of the preceding.

[0015] An electronic device comprising a memory, a processor, and a computer program stored on the memory, the processor implementing the steps of the method of any one of the preceding when executing the program.

[0016] In summary, the technical effects and advantages of the present application are: in view of the defects of the traditional static prediction model that does not consider the time effect of wellbore stability and the dynamic coupling of multiple constraints, the present application is different from the traditional extended reach well extension limit prediction theory which considers the mechanical extension limit, the open hole extension limit and the hydraulic extension limit separately. The present application considers the change of the borehole collapse state caused by the interaction between the drilling fluid and the formation after the drilling fluid contacts the rock of the well wall, and the influence of the equivalent circulating density (ECD), and performs dynamic analysis of the extension limit. The innovative breakthrough of the present application lies in that it first constructs a dynamic correlation model of the time-varying parameters of the borehole state and the extension limit. By introducing a wellbore stability time decay function, the formation mechanical parameters are corrected in real time; a closed-loop feedback mechanism of wellbore instability-annular flow deformation-pressure consumption fluctuation is established to realize dynamic iterative calculation of the ECD; and finally an extension limit prediction system with time sequence characteristics is formed. This dynamic analysis method has significant technical progress compared with the traditional static model, and can effectively improve the design accuracy and construction safety of the extended reach well in complex formations. Attached Figure Description

[0017] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this application. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0018] Figure 1 This is a flowchart of a method for predicting the extension limit of a large-displacement well that considers the change of wellbore condition over time, according to an embodiment of the present invention. Figure 2 This is a drilling safety density window for a large-displacement well in one embodiment of the present invention; Figure 3 This invention illustrates the variation of wellbore collapse pressure and leakage pressure (8-1 / 2 inch) in a large-displacement well with wellbore drilling time in one embodiment of the invention. Figure 4 This invention illustrates the variation in the average wellbore enlargement rate of an 8-1 / 2 inch wellbore with a large displacement well under different drilling speeds, according to one embodiment of the invention. Detailed Implementation

[0019] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0020] Furthermore, the technical features involved in the different embodiments of the present invention described below can be combined with each other as long as they do not conflict with each other.

[0021] This embodiment proposes a method for predicting the extension limit of large-displacement wells, such as... Figures 1-4 As shown, it includes the following steps: S1. Obtain the decay function of formation collapse pressure with wellbore exposure time through rock mechanics experiments, establish a time series-based rock strength degradation coefficient matrix, and update rock strength parameters in real time; This embodiment obtains the decay function of formation collapse pressure with wellbore exposure time through rock mechanics experiments, and establishes a time-series-based rock strength degradation coefficient matrix. Considering the contact time between drilling fluid and formation, rock strength parameters (such as cohesion and internal friction angle) are updated in real time to quantify the time-cumulative effect of wellbore instability risk.

[0022] Wellbore trajectory parameters (inclination angle, azimuth angle), logging-while-drilling data (natural gamma, density, resistivity), mechanical drilling rate of penetration (ROP), and annular pressure (Pan) are obtained through a measurement-while-drilling (LWD) system.

[0023] The variation curves of formation strength parameters with exposure time were obtained through rock mechanics experiments, and a time-series-based rock strength degradation coefficient was established. The rock strength parameters include cohesion C(t) and internal friction angle φ(t). The attenuation functions of cohesion and internal friction angle are primarily considered. in, , The initial cohesion and internal friction angle of the formation, , The degradation coefficient is the result of the experimental fitting. The time required to drill the wellbore.

[0024] Using the contact time ΔT between drilling fluid and formation as an input variable, parameters such as cohesion and internal friction angle are updated in real time to quantify the strength attenuation caused by hydration.

[0025] S2. Using a force-chemical coupling model in cylindrical coordinates, the collapse pressure increment ΔP(t) after drilling time t in different well inclination angles is quantified to establish the time-varying law of wellbore stability; This embodiment utilizes real-time data such as drilling fluid parameters and logging-while-drilling data to dynamically correct the formation collapse pressure gradient and fracture pressure gradient, addressing the shortcomings of traditional models that neglect the long-term contact effect between drilling fluid and formation. A force-chemical coupling model in cylindrical coordinates is employed to quantify the collapse pressure increment at different well inclination angles after drilling time t. Establish the time-varying law of wellbore stability.

[0026] Using the Mohr-Coulomb criterion, a force-chemical coupling model was established based on cylindrical coordinates to calculate the collapse pressure increment of extended reach wells after the drilling fluid has been in contact with the formation for a duration ΔT under real-time well inclination and azimuth conditions. Based on real-time drilling fluid density By determining the change in pore pressure around the wellbore after drilling fluid intrusion into the formation, the change in formation loss pressure with respect to the drilling fluid-formation contact time ΔT is obtained: in, This represents the change in pore pressure around the wellbore over time.

[0027] Based on the initial formation collapse pressure and leakage pressure, and the changes in collapse pressure and leakage pressure due to drilling fluid after wellbore drilling, the real-time values ​​of collapse pressure and leakage pressure are obtained: in, , These are the initial collapse pressure and leakage pressure at the start of well drilling, respectively.

[0028] This embodiment utilizes real-time data such as drilling fluid parameters and logging-while-drilling data to dynamically correct the formation collapse pressure gradient and fracture pressure gradient, addressing the shortcomings of traditional models that neglect the long-term contact effect between drilling fluid and formation. A force-chemical coupling model in cylindrical coordinates is employed to quantify the collapse pressure increment at different well inclination angles after drilling time t. Establish the time-varying law of wellbore stability.

[0029] S3. Based on real-time drilling fluid density data and the dynamic changes in collapse pressure and fracture pressure, determine the changes in wellbore condition with wellbore drilling time, and obtain the wellbore enlargement rate and collapse volume at different depths; This embodiment determines the changes in wellbore status with wellbore drilling time based on real-time drilling fluid density data and dynamic changes in collapse pressure and leakage pressure, thereby obtaining the wellbore enlargement rate and collapse volume at different depths.

[0030] The wellbore enlargement ratio is generated by combining the dynamic changes in drilling fluid density and wellbore collapse pressure. Curves showing variation with well depth and time: Comparison of real-time drilling fluid density With real-time collapse pressure Determine the real-time status of the wellbore: if The wellbore is stable, the wellbore enlargement rate is 0, and the volume of cuttings in the wellbore is only related to the mechanical drilling rate.

[0031] if Wellbore collapse, well diameter enlargement rate Volume of cuttings in the wellbore V C It is related to the wellbore enlargement rate and mechanical drilling rate, i.e. .

[0032] in, This refers to the mechanical drilling speed.

[0033] S4. Establish a dynamic transport model of two layers of cuttings in extended reach wells, considering the dynamic changes in wellbore enlargement rate and wellbore collapse volume, and calculate the changes in cuttings bed thickness under real-time mechanical drilling rate conditions. A two-layer dynamic cuttings transport model was established, and the wellbore enlargement rate was used as the annular cross-sectional area correction factor. The results were as follows: in, Where is the drill bit radius. This refers to the outer diameter of the drill pipe.

[0034] S5. Construct a dynamic database of annular flow channel geometric parameters under non-ideal wellbore morphology, introduce the wellbore enlargement rate η caused by wellbore instability as the flow channel cross-sectional area correction factor, and realize the dynamic iterative calculation of ECD value through the annular two-phase flow ECD prediction model; Combining real-time mechanical drilling rate of RP and cuttings bed thickness The equivalent density of the annulus was calculated using a two-phase flow model. And through time step Iterative updates will be performed.

[0035] in, , The drilling fluid mobility coefficient. This refers to the drilling fluid discharge rate.

[0036] S6. Analyze the variation law of drill string friction torque with well depth under non-ideal wellbore conditions using numerical simulation methods, and determine the dynamic variation law of friction torque; A three-dimensional wellbore trajectory model is constructed based on non-ideal wellbore morphology data. The contact force between the drill string and the wellbore wall is solved using the finite element method. in, The friction coefficient is related to the wellbore condition. The contact normal stress varies with well depth. The inclination angle varies with well depth. This refers to the length of the well section.

[0037] The contact force distribution between the drill string and the enlarged wellbore was simulated using the finite element method, and the peak torque was output. and minimum axial force Curve showing variation with well depth.

[0038] S7. Using the well depth increment ΔL as the optimization variable, simultaneously solve the wellbore stability state, drilling fluid ECD, and tubing friction torque within the time step Δt. Under real-time wellbore stability conditions, determine whether the drilling fluid ECD, tubing friction torque, and axial force have reached critical values. If any one of them reaches a critical value, output the dynamic extension limit. .

[0039] Incremental well depth To optimize the step size, during drilling... Time used in the process In time step Solve for the wellbore stability state. , and .

[0040] Set dual critical conditions: If or or (in (If the top drive rated torque is used), then the current well depth is output as the dynamic extension limit of the extended well. . or This corresponds to two different working conditions.

[0041] This embodiment also provides an apparatus for predicting the dynamic extension limit of a long-displacement well using the above steps, comprising: The first processing unit is used to determine the variation law of wellbore collapse pressure over time based on experimental data.

[0042] The second processing unit is used to determine the variation of wellbore leakage pressure over time based on the real-time drilling fluid density and properties.

[0043] The third processing unit is used to determine the wellbore enlargement rate and the real-time wellbore status based on the real-time drilling fluid density and wellbore collapse pressure.

[0044] The fourth processing unit is used to determine the equivalent circulating density of drilling fluid based on the wellbore enlargement rate and the annular two-phase flow model.

[0045] The fifth processing unit is used to determine the peak value of drill string torque and the minimum value of axial force using the finite element method.

[0046] The sixth processing unit is used to compare whether the equivalent circulating density of drilling fluid and the peak torque of drill string have reached the upper limit, determine whether the axial force at the wellhead is 0, and determine the dynamic extension limit of the extended well.

[0047] This embodiment also provides a computer storage medium storing a computer program that, when executed by a processor, can implement the above-described method steps for determining the dynamic extension limit of a large-displacement well.

[0048] The present invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the above-described method steps for determining the dynamic extension limit of a large-displacement well.

[0049] Based on the above steps, and in conjunction with specific embodiments, the beneficial effects of the present invention are explained as follows: A certain extended reach well has a designed vertical depth of 1440m, a total depth of 6041m, a horizontal displacement of 5317.3m, and a stable inclination angle of 81.64°. The well primarily encountered sandstone and mudstone strata in the Minghuazhen Formation of the Bohai Sea. Laboratory experiments showed that the sandstone strata are relatively loose, with a density ranging from 1.67 to 2.25 g / cm³.3 The mudstone strata contain 40-60% clay minerals, primarily composed of mixed illite and shale. The formation exhibits low compressive strength, with a uniaxial compressive strength of only 1-4 MPa, demonstrating significant plasticity. After soaking in water-based drilling fluid for 30 minutes, the compressive strength decreases by more than 40%. Regression analysis of the formation principal stresses based on formation density integrals and ground leakage experiments indicates that the highest pressure in the overlying strata is approximately 28 MPa, the highest maximum horizontal principal stress is approximately 25 MPa, and the highest maximum horizontal principal stress is approximately 22 MPa.

[0050] In the drilling design, 17-1 / 2 inch, 12-1 / 4 inch, and 8-1 / 2 inch drill bits, 5-inch drill pipe, and 13-3 / 8 inch, 9-5 / 8 inch, and 7-inch casing were used for drilling sections below the second section of the Minghuazhen Formation, respectively. Based on regional drilling practices and the requirements for developing reservoirs with extended reach, the 8-1 / 2 inch drill bit was used for drilling horizontal reservoir sections; therefore, the upper 9-5 / 8 inch casing generally needed to be run to the landing point.

[0051] Taking an 8-1 / 2 inch wellbore as an example, in the traditional method for predicting the extension limit of extended wells, the drilling safety density window is calculated using rock mechanics based on the above fundamental data. If a 9-5 / 8 inch casing is run to a landing point of 5100m, then the upper limit of the equivalent density of the collapse pressure in the horizontal section of the 8-1 / 2 inch wellbore is 1.17 g / cm³. 3 The lower limit of leakage pressure equivalent density is 1.65 g / cm³. 3 Considering the additional drilling fluid density required to prevent wellbore collapse and a safety factor (0.9) to prevent leakage, the safe drilling fluid density for the 8-1 / 2 inch section is 1.20-1.485 g / cm³. 3 The design density for 8-1 / 2 inch well sections is 1.20 g / cm³. 3 The drilling fluid was used at a displacement of 35 L / s. According to the static calculation method for ECD in extended reach wells, when the 8-1 / 2 inch wellbore reached 6410 m, the bottom hole ECD reached 1.485 g / cm³. 3 That is, the hydraulic extension limit is 6410m.

[0052] Referring to the actual drilling parameters of neighboring wells, the friction coefficient of the casing section is taken as 0.20, the friction coefficient of the open hole section as 0.25, and the rated torque of the top drive as 50 kN·m. Using the numerical calculation model of friction torque for extended reach wells, it is found that the axial force at the wellhead is 0 when the 8-1 / 2 inch wellbore drill string is rotary drilled to 7100m, the wellhead torque reaches 40 kN·m when rotary drilled to 6650m, and the axial force at the wellhead is 0 when sliding drilled to 6330m. That is, the mechanical extension limits under different drilling conditions are 6650m and 6330m, respectively. Therefore, comparing the hydraulic extension limit and the mechanical extension limit, the static comprehensive extension limit under rotary drilling conditions is 6410m, and the static comprehensive extension limit under rotary drilling conditions is 6330m.

[0053] According to the method proposed in this invention, the influence of wellbore condition changes on the hydraulic extension limit and mechanical extension limit needs to be considered in the above calculation process. Based on the hydration test results of water-based drilling fluid on formation cores, the strength parameters of the formation change over time after contact with the drilling fluid. Simultaneously, the hydration effect of the drilling fluid on mudstone formations and the seepage effect on sandstone formations alter the pore pressure around the wellbore. Therefore, after the wellbore is drilled, the collapse pressure increases over time, while the leakage pressure decreases slightly over time. Taking an 8-1 / 2 inch horizontal section wellbore as an example, based on the method proposed in this invention, after 25 days of drilling, the collapse pressure increases from the initial 1.17 g / cm³. 3 Gradually increased to 1.33 g / cm³ 3 The leakage pressure increased from the initial 1.65 g / cm³. 3 Gradually decreased to 1.62 g / cm³ 3 At this point, the safe drilling fluid density is 1.35-1.46 g / cm³. 3 .

[0054] In actual drilling, if an 8-1 / 2 inch wellbore still uses a density of 1.20 g / cm³... 3 Water-based drilling fluids cause localized wellbore collapse after more than one day of drilling, with the wellbore enlargement rate increasing with drilling time. According to the calculation method proposed in this invention, when drilling at daily footage of 900m, 300m, and 100m, respectively, the maximum average upper wellbore enlargement rate reaches 4.7%, 9.3%, and 11.7% when drilling from 5100m to 6000m, respectively. Based on this, annular cross-sectional area correction factors are calculated, and the cuttings bed height considering wellbore collapse is further calculated. The cuttings bed and wellbore enlargement rate are then incorporated into real-time ECD calculations, with a drilling fluid static density of 1.20 g / cm³. 3 Considering the irregular wellbore diameter, the bottom hole ECD increases. Calculations show that with a daily drilling depth of 900m, the bottom hole ECD reaches 1.46 g / cm³ at a depth of 6080m. 3When the daily drilling depth is 300m, the bottom hole ECD reaches 1.46g / cm³ at a depth of 5780m. 3 When the daily drilling depth is 100m, the bottom hole ECD reaches 1.46g / cm³ at a depth of 5550m. 3 Therefore, when considering differences in mechanical drilling rate and changes in wellbore condition, the hydraulic extension limit dynamically varies between 5550 and 6080 m.

[0055] Similarly, considering the wellbore conditions at different drilling speeds, the peak torque and minimum axial force of the drill string were calculated using the finite element method. The calculation results show that at a daily footage of 900m, the axial force at the wellhead is 0 when the drill string is rotary drilled to 7093m, the wellhead torque reaches 40 KN·m when rotary drilled to 6645m, and the axial force at the wellhead is 0 when sliding drilled to 6290m; at a daily footage of 300m, the axial force at the wellhead is 0 when the drill string is rotary drilled to 7081m, the wellhead torque reaches 40 KN·m when rotary drilled to 6636m, and the axial force at the wellhead is 0 when sliding drilled to 6220m; at a daily footage of 100m, the axial force at the wellhead is 0 when the drill string is rotary drilled to 7071m, the wellhead torque reaches 40 KN·m when rotary drilled to 6630m, and the axial force at the wellhead is 0 when sliding drilled to 6160m.

[0056] The statistical calculation results, as shown in Table 1, indicate that the comprehensive extension limit calculated using the extended well extension limit prediction method for large-reach wells proposed in this invention, which considers the changes in wellbore condition over time, is smaller than the extension limit obtained by the traditional static analysis method. Furthermore, the slower the mechanical drilling rate during drilling, the smaller the comprehensive extension limit. The method proposed in this invention better reflects the dynamic changes in the wellbore during drilling, avoiding the overestimation of the extended well extension limit by traditional methods.

[0057] Table 1 Although preferred embodiments of the present invention have been described above in conjunction with the accompanying drawings, the present invention is not limited to the specific embodiments described above. The specific embodiments described above are merely illustrative and not limiting. Those skilled in the art can make many specific modifications under the guidance of the present invention without departing from the spirit of the invention and the scope of protection of the claims, and these modifications all fall within the scope of protection of the present invention.

Claims

1. A method for predicting the extension limit of extended wells, characterized in that, Includes the following steps: S1. Obtain the decay function of formation collapse pressure with wellbore exposure time through rock mechanics experiments, establish a time series-based rock strength degradation coefficient matrix, and update rock strength parameters in real time; S2. Using a force-chemical coupling model in cylindrical coordinates, the collapse pressure increment ΔP(t) after drilling time t in different well inclination angles is quantified to establish the time-varying law of wellbore stability; S3. Based on real-time drilling fluid density data and the dynamic changes in collapse pressure and fracture pressure, determine the changes in wellbore condition with wellbore drilling time, and obtain the wellbore enlargement rate and collapse volume at different depths; S4. Establish a dynamic transport model of two layers of cuttings in extended reach wells, considering the dynamic changes in wellbore enlargement rate and wellbore collapse volume, and calculate the changes in cuttings bed thickness under real-time mechanical drilling rate conditions. S5. Construct a dynamic database of annular flow channel geometric parameters under non-ideal wellbore morphology, introduce well diameter expansion rate η as a flow channel cross-sectional area correction factor, and realize dynamic iterative calculation of ECD values ​​through an annular two-phase flow ECD prediction model; S6. Analyze the variation law of drill string friction torque with well depth under non-ideal wellbore conditions using numerical simulation methods, and determine the dynamic variation law of friction torque; S7. Using the well depth increment ΔL as the optimization variable, simultaneously solve the wellbore stability state, drilling fluid ECD, and tubing friction torque within the time step Δt. Under the real-time wellbore stability state condition, determine whether the drilling fluid ECD, tubing friction torque, and axial force have reached the critical value. If any one of them reaches the critical value, output the dynamic extension limit.

2. The method for predicting the extension limit of extended wells according to claim 1, characterized in that, In step S1, the rock strength parameters include cohesion C(t) and internal friction angle φ(t), and their attenuation function is: in, , The initial cohesion and internal friction angle of the formation, , The degradation coefficient is the result of the experimental fitting. The time required to drill the wellbore.

3. The method for predicting the extension limit of extended wells according to claim 2, characterized in that, In step S2, the collapse pressure increment ΔP(t) is calculated using the Mohr-Coulomb criterion. A force-chemical coupling model is established based on cylindrical coordinates to calculate the collapse pressure increment of a large-displacement well after the drilling fluid has been in contact with the formation for a duration ΔT under real-time well inclination and azimuth conditions. Based on real-time drilling fluid density By determining the change in pore pressure around the wellbore after drilling fluid intrusion into the formation, the change in formation loss pressure with respect to the drilling fluid-formation contact time ΔT is obtained: in, This represents the change in pore pressure around the wellbore over time. Based on the initial formation collapse pressure and leakage pressure, and the changes in collapse pressure and leakage pressure due to drilling fluid after wellbore drilling, the real-time values ​​of collapse pressure and leakage pressure are obtained: in, , These are the initial collapse pressure and leakage pressure at the start of well drilling, respectively.

4. The method for predicting the extension limit of extended wells according to claim 3, characterized in that, In step S3, the wellbore enlargement ratio is generated by combining the dynamic changes in drilling fluid density and wellbore collapse pressure. Curves showing variation with well depth and time: The wellbore condition is determined by comparing drilling fluid density. With collapse pressure Sure: like The wellbore is stable, the wellbore enlargement rate is 0, and the volume of cuttings in the wellbore is only related to the mechanical drilling rate. like Wellbore collapse, well diameter enlargement rate The volume of cuttings in the wellbore is related to the wellbore enlargement rate and the rate of drilling. Where ROP is the mechanical drilling rate, V c This represents the volume of rock cuttings within the wellbore.

5. The method for predicting the extension limit of a large-displacement well according to claim 1, characterized in that, In step S4, a two-layer dynamic cuttings transport model is established, and the wellbore enlargement rate is used as the annular cross-sectional area correction factor, resulting in: in, Where is the drill bit radius. This refers to the outer diameter of the drill pipe.

6. The method for predicting the extension limit of extended wells according to claim 1, characterized in that, In step S5, the annular equivalent density ECD(t) is calculated using a two-phase flow model, and its expression is: in, For the cross-sectional area of ​​the annulus, , The drilling fluid mobility coefficient. H represents drilling fluid displacement. c The thickness of the rock cuttings bed.

7. The method for predicting the extension limit of extended wells according to claim 1, characterized in that, In step S6, the frictional torque and axial force of the drill pipe are solved using the finite element method, and the expressions are as follows: in, The friction coefficient is related to the wellbore condition. The contact normal stress varies with well depth. The inclination angle varies with well depth. This refers to the length of the well section.

8. An apparatus for implementing the method according to any one of claims 1-7, characterized in that, include: The first processing unit is used to determine the variation law of wellbore collapse pressure over time based on experimental data; The second processing unit is used to determine the variation law of wellbore fracture pressure over time based on the real-time drilling fluid density. The third processing unit is used to determine the wellbore enlargement rate and the real-time wellbore status based on the real-time drilling fluid density and collapse pressure. The fourth processing unit is used to calculate the drilling fluid equivalent circulating density (ECD) based on the wellbore enlargement ratio and the annular two-phase flow model. The fifth processing unit is used to determine the peak drill string torque and the minimum wellhead axial force using the finite element method. The sixth processing unit is used to compare whether the peak torque of the ECD and the drill string reaches the critical value, whether the axial force at the wellhead is 0, and to determine the dynamic extension limit of the extended well.

9. A computer storage medium having a computer program stored thereon, characterized in that, When the program is executed by a processor, it implements the steps of the method according to any one of claims 1-7.

10. An electronic device comprising a memory, a processor, and a computer program stored in the memory, characterized in that, When the processor executes the program, it implements the steps of the method according to any one of claims 1-7.

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