Design method of the maximum length of horizontal section in horizontal wells

Abstract

The present invention discloses a method for designing the maximum length of a horizontal section of a horizontal well. The design method comprises: performing actual drilling processing on a preset wellbore trajectory according to a wellbore trajectory change law of a well area to obtain a predicted wellbore trajectory, substituting an average value of parameters for evaluating formation mud content of multiple drilled wells into a first relationship model for evaluating the correlation between formation mud content and friction coefficient to obtain a predicted friction coefficient, determining a predicted dynamic-static friction coefficient ratio of a horizontal well to be predicted according to the predicted wellbore trajectory and the predicted friction coefficient, and selecting a corresponding second relationship model between the friction coefficient and the maximum length of the horizontal section according to the predicted dynamic-static friction coefficient ratio, so that the predicted friction coefficient can be substituted into the second relationship model to determine the maximum length of the horizontal section of the horizontal well to be predicted. Then, by performing actual drilling processing on the preset wellbore trajectory and simulating the friction constraints of the horizontal well under actual drilling conditions, the actual drilling constraints can be met.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas field development, and in particular relates to a method for designing the maximum length of a horizontal section of a horizontal well. Background Art

[0002] Currently, horizontal well development technology is widely used in oil and gas drilling and production projects. A key issue in horizontal well development design is determining the length of the horizontal section. Generally speaking, a longer horizontal section increases the contact area between the wellbore and the reservoir, facilitating oil and gas recovery. However, a longer horizontal section also increases the contact area between the drill string and the wellbore wall, resulting in greater frictional torque and loads on the wellhead equipment. When friction reaches the equipment's limit, drilling accidents are more likely to occur. Therefore, the design and prediction of the horizontal section length of horizontal wells is crucial.

[0003] The horizontal section length design of horizontal wells can be divided into many categories according to different constraints: (1) Ultimate production constraint: A mathematical relationship model for the ultimate length of the horizontal section of a horizontal well is established. Under specific reservoir and fluid conditions, the ultimate length of the horizontal section is inferred from the calculation formula of the ultimate production of the horizontal well. This method is based on the reservoir production angle and does not fully consider factors such as engineering drilling. (2) Friction loss constraint: The optimal length of the horizontal section is the length when the friction loss reduces the production capacity by 20%. This method is based on the impact of the pressure drop in the horizontal wellbore on production. It mainly considers the pressure drop caused by the friction of the pipe wall, but does not study the friction constraint caused by friction on the drill bit. (3) Mechanical extension limit constraint: This includes the operating limit of the drill bit and the operating limit of the casing. It mainly considers the friction torque problem of the drill bit during the drilling operation. (4) Hydraulic extension limit constraint: It refers to the drilling hydraulic depth allowed under the premise of maintaining normal circulation of the drilling fluid and clean wellbore. (5) Open hole extension limit constraint: It refers to the horizontal well depth when the open hole bottom is crushed or leaking, which is mainly affected by formation factors. Although these methods can design or predict the horizontal section length of horizontal wells, they cannot meet the actual drilling constraints, resulting in large deviations. Summary of the Invention

[0004] In response to the above-mentioned defects or shortcomings of the prior art, the present invention provides a method for designing the maximum length of the horizontal section of a horizontal well, aiming to solve the technical problem that the methods in the prior art cannot meet the actual drilling constraints and the designed or predicted horizontal section length has large deviations.

[0005] To achieve the above-mentioned object, the present invention provides, in a first aspect, a method for designing the maximum length of a horizontal section of a horizontal well, wherein the method for designing the maximum length of a horizontal section of a horizontal well comprises:

[0006] Determine the preset wellbore trajectory of the horizontal well to be predicted based on the exploration data;

[0007] According to the wellbore trajectory change law of the well area where the horizontal well to be predicted is located, the preset wellbore trajectory is actually drilled to obtain the predicted wellbore trajectory of the horizontal well to be predicted;

[0008] Obtaining a first relationship model for evaluating the correlation between formation mud content and friction coefficient in the well area;

[0009] Substituting an average value of parameters used to evaluate formation shale content of multiple wells drilled in the well area into the first relationship model to obtain a predicted friction coefficient of the horizontal well to be predicted;

[0010] Determine the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted according to the predicted wellbore trajectory and the predicted friction coefficient;

[0011] Obtaining a second relationship model between the friction coefficient of the well area and the limit length of the horizontal section;

[0012] A corresponding second relationship model is selected according to the predicted dynamic-static friction coefficient ratio, and the predicted friction coefficient is substituted into the second relationship model to determine the horizontal section limit length of the horizontal well to be predicted.

[0013] In an embodiment of the present invention, the preset wellbore trajectory is subjected to actual drilling processing according to the wellbore trajectory variation law of the well area where the horizontal well to be predicted is located, so as to obtain the predicted wellbore trajectory of the horizontal well to be predicted, including:

[0014] Select multiple wellbore trajectories and logging data of drilled wells in the well area;

[0015] Calculate the wellbore trajectory tortuosity of any benchmark logging section based on the wellbore trajectory and logging data of each drilled well;

[0016] Conduct statistical analysis on the tortuosity of multiple drilled well trajectories to determine the changing patterns of well trajectories;

[0017] The preset wellbore trajectory is processed by actual drilling according to the change law of the wellbore trajectory to obtain the predicted wellbore trajectory of the horizontal well to be predicted.

[0018] In the embodiment of the present invention, the calculation characteristic parameter of the wellbore trajectory tortuosity is the wellbore curvature vector change rate. The calculation formula of the wellbore curvature vector change rate of the reference logging section is:

[0019]

[0020] Where G i It refers to the change rate of the wellbore curvature vector of the i-th benchmark logging section, ° / 300m 2 ;K i , K i+1 are the average borehole curvatures of the i-th benchmark logging section and the i+1-th benchmark logging section, ° / 30m 2;ω i,i+1 is the angle between the normal direction of the plane where the i-th benchmark logging section and the i+1-th benchmark logging section are located, in degrees; ΔL is the average length of the two logging sections of the i-th benchmark logging section and the i+1-th benchmark logging section, in meters.

[0021] In an embodiment of the present invention, statistical analysis of the tortuosity of multiple drilled wellbore trajectories to determine the variation pattern of the wellbore trajectories includes:

[0022] Calculate the standard deviation of the change rate of the wellbore curvature vector in the vertical section, the deflection section and the horizontal section of each drilled well;

[0023] The standard deviations of multiple wells drilled in the same well section are weighted averaged to determine the variation pattern of the well trajectory.

[0024] In an embodiment of the present invention, the preset wellbore trajectory is subjected to actual drilling processing according to the wellbore trajectory change law to obtain the predicted wellbore trajectory of the horizontal well to be predicted, including:

[0025] Generate a borehole curvature vector change rate that conforms to the normal distribution and has an average value of 0 according to the standard deviation after weighted average;

[0026] The predicted wellbore trajectory is generated according to the preset correction formula, the wellbore curvature vector change rate and the preset wellbore trajectory, wherein the preset correction formula is:

[0027]

[0028] Where, is the well inclination angle of the i-th point after correction, (°); a i is the well inclination angle of the i-th point before correction, (°); G j is the change rate of the borehole curvature vector that conforms to the normal distribution, ° / 300m 2 ;ΔL j , ΔL j-1 are the lengths of the j-th and j-1-th benchmark logging sections, respectively.

[0029] In an embodiment of the present invention, before obtaining a first relationship model for evaluating the correlation between formation shale content and friction coefficient in a well area, the method further includes:

[0030] Perform inversion calculations based on multiple wellbore trajectories and drilling data to obtain the maximum dynamic friction coefficient in different sections of the open hole;

[0031] Calculate the natural logarithm of the average natural gamma within the same section of multiple drilled open hole sections;

[0032] The correlation between the formation mud content and the friction coefficient was analyzed based on the natural logarithm of the average natural gamma and the maximum dynamic friction coefficient to obtain the first relationship model.

[0033] In an embodiment of the present invention, determining the predicted dynamic-static friction coefficient ratio of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient includes:

[0034] The predicted maximum dynamic friction of the horizontal well to be predicted is calculated based on the predicted wellbore trajectory and the predicted friction coefficient;

[0035] The predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted is determined based on the optimal critical value principle of the predicted maximum dynamic friction and dynamic and static friction.

[0036] In the embodiment of the present invention, before obtaining the second relationship model between the friction coefficient of the well area and the limit length of the horizontal section, the method further includes:

[0037] Determine the dynamic and static friction coefficient ratio of each drilled well based on the difference in hook load before and after the occurrence of the support pressure condition in multiple drilled wells;

[0038] Under the condition of the same dynamic-static friction coefficient ratio, a second relationship model is established based on the friction coefficient of the drilled well and the measured length of the horizontal section.

[0039] In an embodiment of the present invention, the design method further includes:

[0040] When the number of sweet spots and target points of the horizontal well to be predicted is more than three and they are not collinear, the horizontal section limit length of the horizontal well to be predicted needs to be subtracted from the horizontal section length converted from multiple non-collinear target points.

[0041] In an embodiment of the present invention, the design method further includes:

[0042] When the drilling fluid density of the horizontal well to be predicted does not meet the loss constraint or collapse constraint, drilling of the horizontal section is stopped.

[0043] Through the above technical solution, the method for designing the maximum length of the horizontal section of a horizontal well provided by the embodiment of the present invention has the following beneficial effects:

[0044] In the above technical solution, the preset wellbore trajectory can be first subjected to actual drilling processing according to the wellbore trajectory change law of the well area where the horizontal well to be predicted is located to obtain the predicted wellbore trajectory of the horizontal well to be predicted, and then the average value of the parameters used to evaluate the mud content of the formation of multiple drilled wells in the well area is substituted into the first relationship model used to evaluate the correlation between the mud content of the formation and the friction coefficient to obtain the predicted friction coefficient of the horizontal well to be predicted, and then the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted is determined according to the predicted wellbore trajectory and the predicted friction coefficient, and the corresponding second relationship model between the friction coefficient and the maximum length of the horizontal section is selected according to the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted, so that the predicted friction coefficient can be substituted into the second relationship model to determine the maximum length of the horizontal section of the horizontal well to be predicted. The present invention performs actual drilling processing on the preset wellbore trajectory and simulates the friction constraints of the horizontal well under actual drilling conditions, so that the predicted maximum length of the horizontal section can meet the actual drilling constraints, thereby achieving the purpose of improving the prediction accuracy of the maximum length of the horizontal section.

[0045] Other features and advantages of the embodiments of the present invention will be described in detail in the subsequent detailed description. BRIEF DESCRIPTION OF THE DRAWINGS

[0046] The accompanying drawings are used to provide a further understanding of the embodiments of the present invention and constitute a part of the specification. Together with the following detailed description, they are used to explain the embodiments of the present invention, but do not constitute a limitation of the embodiments of the present invention. In the accompanying drawings:

[0047] Figure 1 is a flow chart of a method for designing the maximum length of a horizontal section of a horizontal well according to one embodiment of the present invention;

[0048] Figure 2 is a flow chart of step 200 in a method for designing a maximum length of a horizontal section of a horizontal well according to an embodiment of the present invention;

[0049] Figure 3 is a schematic diagram of a first relationship model according to an embodiment of the present invention;

[0050] Figure 4 is a schematic diagram of a second relationship model according to an embodiment of the present invention;

[0051] Figure 5 is a schematic diagram of another second relationship model according to an embodiment of the present invention. DETAILED DESCRIPTION

[0052] The following describes the specific implementation of the embodiment of the present invention in detail with reference to the accompanying drawings. It should be understood that the specific implementation described herein is only used to illustrate and explain the embodiment of the present invention and is not used to limit the embodiment of the present invention.

[0053] It should be noted that if the implementation methods of this application involve directional indications (such as up, down, left, right, front, back, etc.), such directional indications are only used to explain the relative position relationship, movement status, etc. between the various components under a certain specific posture (as shown in the accompanying drawings). If the specific posture changes, the directional indication will also change accordingly.

[0054] In addition, if there are descriptions involving "first", "second", etc. in the embodiments of this application, the descriptions of "first", "second", etc. are only for descriptive purposes and cannot be understood as indicating or implying their relative importance or implicitly indicating the number of the indicated technical features. Therefore, the features specified as "first" and "second" may explicitly or implicitly include at least one of such features. In addition, the technical solutions between the various embodiments can be combined with each other, but they must be based on the fact that they can be implemented by ordinary technicians in this field. When the combination of technical solutions is contradictory or cannot be implemented, it should be deemed that such a combination of technical solutions does not exist and is not within the scope of protection required by this application.

[0055] Figure 1 The flowchart of the method for designing the maximum length of the horizontal section of a horizontal well according to one embodiment of the present invention is schematically shown. Figure 1 As shown, the present invention provides a method for designing the maximum length of a horizontal section of a horizontal well, wherein the method for designing the maximum length of a horizontal section of a horizontal well comprises the following steps:

[0056] Step 100: Determine a preset wellbore trajectory of a horizontal well to be predicted based on exploration data.

[0057] Specifically, the exploration data may be geological exploration and oil and gas reservoir targets. According to the geological exploration and oil and gas reservoir targets, the wellbore trajectory of the predicted horizontal well may be preset first, and the preset wellbore trajectory is a smooth straight line in the vertical well section and the horizontal section, and a smooth curve in the inclination section.

[0058] Step 200 : Perform actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory variation law of the well area where the horizontal well to be predicted is located, so as to obtain the predicted wellbore trajectory of the horizontal well to be predicted.

[0059] Specifically, the wellbore trajectory change law of the well area where the horizontal well to be predicted is located can be obtained in advance, and the wellbore trajectory change law can reflect that the wellbore trajectory after actual drilling is not smooth, but has uneven changes. The preset wellbore trajectory can be processed by actual drilling based on the wellbore trajectory change law, so that the predicted wellbore trajectory is closer to the actual drilled wellbore trajectory.

[0060] Step 300: Obtain a first relationship model for evaluating the correlation between formation mud content and friction coefficient in a well area.

[0061] Specifically, different well sections have different formation shale contents, and different formation shale contents result in different friction coefficients. Therefore, a first relationship model for evaluating the correlation between formation shale content and friction coefficient can be established in advance based on logging data of wells drilled in the well area. More specifically, the first relationship model can be a fitting equation.

[0062] Step 400: Substitute the average value of the parameters used to evaluate the mud content of the formation of multiple wells drilled in the well area into the first relationship model to obtain the predicted friction coefficient of the horizontal well to be predicted.

[0063] Specifically, the average value of the parameters used to evaluate formation mud content in the logging data of multiple wells drilled in the well area can be used as the parameter used to evaluate formation mud content of the horizontal well to be predicted, and substituted into the first relationship model to calculate the predicted friction coefficient.

[0064] Step 500: Determine the predicted dynamic-static friction coefficient ratio of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient.

[0065] Furthermore, the predicted wellbore trajectory and predicted friction coefficient can be set in the friction calculation software (eg, LANDMARK), and the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted can be output through the friction calculation software.

[0066] Step 600: Obtain a second relationship model between the friction coefficient of the well area and the limit length of the horizontal section.

[0067] Furthermore, a second relationship model between the friction coefficient and the limit length of the horizontal section under different dynamic and static friction coefficient ratios can be determined in advance based on logging data of multiple wells drilled in the well area.

[0068] Step 700 : Select a corresponding second relationship model according to the predicted dynamic-static friction coefficient ratio, and substitute the predicted friction coefficient into the second relationship model to determine the limit length of the horizontal section of the horizontal well to be predicted.

[0069] In the above technical solution, the preset wellbore trajectory can be first subjected to actual drilling processing according to the wellbore trajectory change law of the well area where the horizontal well to be predicted is located to obtain the predicted wellbore trajectory of the horizontal well to be predicted, and then the average value of the parameters used to evaluate the mud content of the formation of multiple drilled wells in the well area is substituted into the first relationship model used to evaluate the correlation between the mud content of the formation and the friction coefficient to obtain the predicted friction coefficient of the horizontal well to be predicted, and then the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted is determined according to the predicted wellbore trajectory and the predicted friction coefficient, and the corresponding second relationship model between the friction coefficient and the maximum length of the horizontal section is selected according to the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted, so that the predicted friction coefficient can be substituted into the second relationship model to determine the maximum length of the horizontal section of the horizontal well to be predicted. The present invention performs actual drilling processing on the preset wellbore trajectory and simulates the friction constraints of the horizontal well under actual drilling conditions, so that the predicted maximum length of the horizontal section can meet the actual drilling constraints, thereby achieving the purpose of improving the prediction accuracy of the maximum length of the horizontal section.

[0070] Figure 2 The flowchart of step 200 in the method for designing the maximum length of the horizontal section of a horizontal well according to one embodiment of the present invention is schematically shown. Figure 2 As shown, in this embodiment of the present invention, step 200, performing actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory change law of the well area where the horizontal well to be predicted is located, so as to obtain the predicted wellbore trajectory of the horizontal well to be predicted, includes:

[0071] Step 210 : Select multiple wellbore trajectories and logging data of drilled wells in the well area.

[0072] Step 220 , calculating the wellbore trajectory tortuosity of any reference logging section based on the wellbore trajectory and logging data of each drilled well.

[0073] Specifically, in the logging data of the drilled well, every 30m is a reference logging section, and the wellbore trajectory tortuosity of each reference logging section is calculated so as to summarize the change pattern of the wellbore trajectory.

[0074] Step 230 : Statistically analyze the tortuosity of the wellbore trajectories of the multiple drilled wells to determine the variation pattern of the wellbore trajectories.

[0075] Furthermore, each drilled well has multiple calculated wellbore trajectory tortuosity, which can be used to comprehensively reflect the wellbore trajectory change pattern in the well area through statistical analysis.

[0076] Step 240 : Perform actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory change rule to obtain the predicted wellbore trajectory of the horizontal well to be predicted.

[0077] In this embodiment, the tortuosity of each wellbore trajectory that has been drilled is calculated and statistically analyzed so that the variation pattern of the wellbore trajectory for actual drilling of the preset wellbore trajectory is closer to reality, thereby ensuring the accuracy of the predicted wellbore trajectory.

[0078] In the embodiment of the present invention, the calculation characteristic parameter of the wellbore trajectory tortuosity is the wellbore curvature vector change rate. The calculation formula of the wellbore curvature vector change rate of the reference logging section is:

[0079]

[0080] Where G i It refers to the change rate of the wellbore curvature vector of the i-th benchmark logging section, ° / 300m 2 ;K i , K i+1 are the average wellbore curvatures of the i-th benchmark logging section and the i+1-th benchmark lateral well section, ° / 30m 2 ;ω i,i+1 is the angle between the normal direction of the plane where the i-th benchmark logging section and the i+1-th benchmark logging section are located, in degrees; ΔL is the average length of the two logging sections of the i-th benchmark logging section and the i+1-th benchmark logging section, in meters.

[0081] Specifically, the wellbore trajectory tortuosity refers to the degree to which the wellbore curvature of the actual drilled wellbore trajectory changes rapidly. The faster the wellbore curvature changes, the greater the wellbore trajectory tortuosity. Therefore, a characteristic parameter, the wellbore curvature vector change rate, can be introduced to quantitatively describe the wellbore trajectory tortuosity within the benchmark logging section.

[0082] In an embodiment of the present invention, step 230 of performing statistical analysis on the tortuosity of multiple drilled wellbore trajectories to determine the variation pattern of the wellbore trajectories includes:

[0083] Step 250 , calculating the standard deviation of the change rate of the wellbore curvature vector of each drilled well in the vertical well section, the deflection section, and the horizontal section.

[0084] Specifically, after calculating the borehole curvature vector change rate of each drilled benchmark logging section, the standard deviation of each drilled well in the vertical section, the deflection section and the horizontal section can be calculated separately. The standard deviation can be used to measure the distribution law of the borehole curvature vector change rate in different sections.

[0085] Step 260 : weighted average the standard deviations of multiple wells drilled in the same well section to determine the variation pattern of the wellbore trajectory.

[0086] Specifically, considering that different wells have different trajectory control capabilities, the standard deviations of multiple drilled wells in the same well section can be weighted averaged so that the standard deviation after weighted average comprehensively considers the trajectory control capability during the actual drilling process. The standard deviation after weighted average reflects the degree of discreteness of the wellbore curvature vector change rate. The larger the value, the more the wellbore curvature in the actual drilling trajectory deviates from the wellbore curvature of the designed wellbore trajectory, and the greater the tortuosity of the wellbore trajectory.

[0087] In an embodiment of the present invention, step 240, performing actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory variation law to obtain the predicted wellbore trajectory of the horizontal well to be predicted, includes:

[0088] Step 270 : Generate a wellbore curvature vector change rate that conforms to a normal distribution and has an average value of 0 based on the weighted average standard deviation and the preset wellbore trajectory.

[0089] Step 280: Generate a predicted wellbore trajectory based on a preset correction formula, the wellbore curvature vector change rate, and the preset wellbore trajectory, wherein the preset correction formula is:

[0090]

[0091] Where, is the well inclination angle of the i-th point after correction, (°); a i is the well inclination angle of the i-th point before correction, (°); G j is the change rate of the borehole curvature vector that conforms to the normal distribution, ° / 300m 2 ;ΔL j , ΔL j-1 are the lengths of the j-th and j-1-th benchmark logging sections respectively; j=3 means that the correction starts from the third well inclination angle.

[0092] Specifically, step 280 includes: generating a to-be-corrected wellbore trajectory based on a preset wellbore trajectory and a wellbore curvature vector change rate; and generating a predicted wellbore trajectory based on a preset correction formula and the to-be-corrected wellbore trajectory. If the to-be-corrected wellbore trajectory generated based on the preset wellbore trajectory and the wellbore curvature vector change rate is a non-smooth curve, then it is necessary to perform a drilling-based correction on the well inclination angle at each point using a preset correction formula. The parameters for the drilling-based correction can be derived from logging parameters of wells already drilled in the well area, so that the predicted wellbore trajectory, after the drilling-based correction, becomes a smooth curve.

[0093] In an embodiment of the present invention, before step 300 of obtaining a first relationship model for evaluating the correlation between formation shale content and friction coefficient in a well area, the method further includes:

[0094] Inversion calculations are performed based on multiple wellbore trajectories and drilling data to obtain the maximum dynamic friction coefficient in different sections of the open hole.

[0095] Specifically, an inversion method and friction calculation software are used to calculate the friction coefficients of the casing and openhole sections corresponding to the run-in operation, using the drill string assembly parameters, the wellbore trajectory, and drilling data used during the actual drilling process. More specifically, the friction coefficient of the openhole section has significant uncertainty due to the irregular wellbore caused by unstable wellbore walls, as well as the presence of mudcake and cuttings beds. For safety reasons, the friction coefficient of the openhole section is calculated based on its maximum dynamic friction coefficient. Furthermore, the vertical section, the buildup section, and the horizontal section can form the openhole section. Therefore, at least the maximum dynamic friction coefficients of the vertical, buildup, and horizontal sections can be determined.

[0096] Calculate the natural logarithm of the average natural gamma within the same section of multiple drilled open hole sections.

[0097] Specifically, the formation mud content can be evaluated by natural gamma. The relationship between natural gamma and formation mud content is:

[0098]

[0099]

[0100] Where, I GR is the natural gamma coefficient; GR is the natural gamma; GR sh is the maximum value of natural gamma, which can be 50; GR cl is the minimum value of natural gamma, which can be 10; V sh is the formation mud content; GCUR is the Hillich index.

[0101] That is, the mud content of the formation can be characterized by calculating the natural logarithm of the average natural gamma in the same section of multiple drilled open hole sections.

[0102] The correlation between the formation mud content and the friction coefficient was analyzed based on the natural logarithm of the average natural gamma and the maximum dynamic friction coefficient to obtain the first relationship model.

[0103] More specifically, see Figure 3 The natural logarithm of the average natural gamma and the maximum dynamic friction coefficient at the same well section position can determine a coordinate value, and multiple coordinate values ​​can be determined for multiple different well section positions. By fitting equations for multiple coordinate values, the first relationship model for evaluating the correlation between formation mud content and friction coefficient can be obtained.

[0104] In addition, in step 400, the natural gamma of multiple drilled open hole sections in the well area can be averaged as the natural gamma prediction value of the horizontal well to be predicted, and the natural logarithm of the natural gamma prediction value can be substituted into the first relationship model to determine the maximum dynamic friction coefficient of the horizontal well to be predicted.

[0105] In an embodiment of the present invention, step 500 of determining the predicted dynamic-static friction coefficient ratio of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient includes:

[0106] Step 510 : Calculate the predicted maximum dynamic friction of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient.

[0107] By using friction calculation software, setting drilling tool assembly parameters, predicted wellbore trajectory, predicted friction coefficient and other drilling data, the predicted maximum dynamic friction of the horizontal well to be predicted can be calculated.

[0108] Step 520 : Determine the predicted dynamic-static friction coefficient ratio of the horizontal well to be predicted based on the optimal critical value principle of the predicted maximum dynamic friction and the dynamic-static friction.

[0109] Specifically, according to the predicted maximum dynamic friction obtained by the above calculation and the optimal critical value principle of a difference of 20 tons between dynamic and static friction, the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted can be determined.

[0110] In the embodiment of the present invention, before step 600, obtaining the second relationship model between the friction coefficient of the well area and the limit length of the horizontal section, the method further includes:

[0111] Step 610: Determine the dynamic and static friction coefficient ratios of the drilled wells according to the difference in hook loads before and after the occurrence of the support pressure condition in the plurality of drilled wells.

[0112] Step 620: Under the condition of the same dynamic-static friction coefficient ratio, a second relationship model is established based on the friction coefficient of the drilled well and the measured length of the horizontal section.

[0113] Specifically, see Figure 4 and Figure 5 According to the difference in the hook load before and after the support pressure situation occurs in the drilled wells in the well area, the dynamic and static friction coefficient ratio of each drilled well can be determined, for example: 0.5 and 0.55, and the friction coefficients and the measured lengths of the horizontal sections of the drilled wells belonging to the same dynamic and static friction coefficient ratio are used to establish a second relationship model for evaluating the friction coefficient and the maximum length of the horizontal section of the well area. There may be multiple dynamic and static friction coefficient ratios of the drilled wells, and there are also multiple corresponding second relationship models.

[0114] In step 700, a selection can be made from a plurality of second relationship models based on the predicted dynamic-static friction coefficient ratio obtained above to select a second relationship model corresponding to the predicted dynamic-static friction coefficient ratio, and the predicted friction coefficient obtained above, that is, the maximum dynamic friction coefficient of the horizontal well to be predicted, is substituted into the corresponding second relationship model, thereby determining the maximum length of the horizontal section of the horizontal well to be predicted.

[0115] In an embodiment of the present invention, the design method further includes:

[0116] Step 800: When the number of sweet spots and target points of the horizontal well to be predicted is more than three and they are not collinear, the horizontal section limit length of the horizontal well to be predicted needs to be subtracted from the horizontal section length converted from the multiple non-collinear target points.

[0117] Specifically, when there are three or more sweet spots and targets and they are not collinear, the friction will increase accordingly. The formula for calculating the horizontal segment length converted from multiple non-collinear targets is:

[0118]

[0119] Where ΔLp is the horizontal length of the non-collinear multi-target points, m; E is the elastic modulus of the string material, Pa; I is the bending moment of inertia of the string, m4; γ1 is the angle between the line between the first and second targets and the line between the second and third targets, (°); γ i-1 is the angle between the line connecting the i-1th and i-th targets and the line connecting the i-th and i+1th targets, (°); γ i-2 is the angle between the line connecting the i-2nd and i-1th targets and the line connecting the i-1st and i-th targets, (°); ΔL1, ΔL2, ΔL i , ΔL i-1 , ΔL i-2 are the lengths between the 1st and 2nd targets, between the 2nd and 3rd targets, between the i-th and i+1 targets, between the i-1th and i targets, and between the i-2th and i-1th targets respectively; ω i-2 is the angle between the plane normal formed by the i-2, i-1, and i targets and the plane normal formed by the i-1, i, and i+1 targets, (°); q m It is the linear buoyancy weight of the pipe string in the drilling fluid, N / m.

[0120] In addition, when the number of sweet spots and target points is less than or equal to two: ΔLp=0.

[0121] In an embodiment of the present invention, the design method further includes:

[0122] When the drilling fluid density of the horizontal well to be predicted does not meet the loss constraint or collapse constraint, drilling of the horizontal section is stopped.

[0123] Specifically, during the drilling process, the formation's pressure bearing capacity is limited. If the drilling fluid density is too high, it is easy to cause leakage. Therefore, to ensure the safety of the drilling operation, the drilling fluid density should meet the leakage constraint. The leakage constraint formula is:

[0124]

[0125] Where, ρm Refers to the drilling fluid density, g / cm3; ρ max Refers to the maximum pressure equivalent density when the formation does not break, g / cm3; P l Refers to the cycle pressure loss, MPa; P cut Refers to the additional pressure loss caused by cuttings, MPa; Refers to the total length of the drill string.

[0126] Furthermore, during the drilling process, if the formation collapses, the horizontal section cannot continue to extend. Therefore, the drilling fluid density should meet the collapse constraint. The collapse constraint formula is:

[0127]

[0128] Where, ρ m Refers to the drilling fluid density, g / cm3; P l Refers to the cycle pressure loss, MPa; P cut Refers to the additional pressure loss caused by cuttings, MPa; ρ p Pore ​​pressure equivalent density, g / cm 3 ρ t Collapse pressure equivalent density, g / cm 3 ; Refers to the total length of the drill string.

[0129] In addition, the present invention also provides a processor, which is configured to execute the method for designing the maximum length of the horizontal section of the horizontal well described above.

[0130] In addition, the present invention provides a machine-readable storage medium having instructions stored thereon, wherein when the instructions are executed by a processor, the method for designing the maximum length of the horizontal section of a horizontal well as described above is implemented.

[0131] Those skilled in the art will appreciate that the embodiments of the present application can be provided as methods, systems, or computer program products. Therefore, the present application can adopt the form of a complete hardware embodiment, a complete software embodiment, or an embodiment in combination with software and hardware. Moreover, the present application can adopt the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to magnetic disk storage, CD-ROM, optical storage, etc.) that contain computer-usable program code.

[0132] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or box in the flowchart and / or block diagram, as well as the combination of the processes and / or boxes in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the steps in the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0133] These computer program instructions may also be stored in a computer readable memory that can direct a computer or other programmable data processing device to work in a specific manner, so that the instructions stored in the computer readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0134] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operational steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing the instructions executed on the computer or other programmable device for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 The steps for the function specified in one or more boxes.

[0135] In a typical configuration, a computing device includes one or more processors (CPUs), input / output interfaces, network interfaces, and memory.

[0136] The memory may include non-permanent memory in a computer-readable medium, random access memory (RAM) and / or non-volatile memory in the form of read-only memory (ROM) or flash RAM. The memory is an example of a computer-readable medium.

[0137] Computer-readable media includes permanent and non-permanent, removable and non-removable media that can be implemented by any method or technology to store information. The information can be computer-readable instructions, data structures, program modules, or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technology, compact disc read-only memory (CD-ROM), digital versatile disc (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other non-transmission media that can be used to store information that can be accessed by a computing device. As defined herein, computer-readable media does not include transitory computer-readable media (transitory media), such as modulated data signals and carrier waves.

[0138] It should also be noted that the terms "comprises," "includes," or any other variations thereof are intended to encompass non-exclusive inclusion, such that a process, method, commodity, or apparatus that includes a series of elements includes not only those elements but also other elements not explicitly listed, or includes elements inherent to such process, method, commodity, or apparatus. In the absence of further limitations, an element defined by the phrase "comprises a ..." does not exclude the presence of other identical elements in the process, method, commodity, or apparatus that includes the element.

[0139] The above are merely embodiments of the present application and are not intended to limit the present application. For those skilled in the art, the present application may have various changes and variations. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present application should all be included within the scope of the claims of the present application.

Claims

1. A method for designing the maximum length of a horizontal section of a horizontal well, characterized in that: The design method includes: Determine the preset wellbore trajectory of the horizontal well to be predicted based on the exploration data; Performing actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory change law of the well area where the horizontal well to be predicted is located, so as to obtain a predicted wellbore trajectory of the horizontal well to be predicted; Obtaining a first relationship model for evaluating the correlation between formation mud content and friction coefficient in the well area; Substituting an average value of parameters used to evaluate formation shale content of multiple wells drilled in the well area into the first relationship model to obtain a predicted friction coefficient of the horizontal well to be predicted; Determining a predicted dynamic-static friction coefficient ratio of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient; Obtaining a second relationship model between the friction coefficient of the well area and the limit length of the horizontal section; Selecting the corresponding second relationship model according to the predicted dynamic-static friction coefficient ratio, and substituting the predicted friction coefficient into the second relationship model to determine the horizontal section limit length of the horizontal well to be predicted; Before obtaining the first relationship model for evaluating the correlation between formation mud content and friction coefficient in the well area, the method further includes: Performing inversion calculations based on the wellbore trajectories and drilling data of the plurality of drilled wells to obtain the maximum dynamic friction coefficient of the open hole section in different sections; Calculating the natural logarithm of the average natural gamma of the plurality of drilled open hole sections within the same section; performing a correlation analysis between formation mud content and friction coefficient based on the natural logarithm of the average natural gamma and the maximum dynamic friction coefficient to obtain the first relationship model; Determining the predicted dynamic-static friction coefficient ratio of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient includes: Calculate the predicted maximum dynamic friction of the horizontal well to be predicted based on the predicted wellbore trajectory and the predicted friction coefficient; Determining the predicted dynamic and static friction coefficient ratio of the horizontal well to be predicted according to the optimal critical value principle of the predicted maximum dynamic friction and the dynamic and static friction; Before obtaining the second relationship model between the friction coefficient of the well area and the limit length of the horizontal section, the method further includes: Determining the dynamic and static friction coefficient ratios of the drilled wells according to the difference in hook loads before and after the occurrence of the support pressure condition in the plurality of drilled wells; Under the condition of the same dynamic-static friction coefficient ratio, the second relationship model is established according to the friction coefficient of the drilled well and the measured length of the horizontal section.

2. The method for designing the maximum length of the horizontal section of a horizontal well according to claim 1, characterized in that: The step of performing actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory variation law of the well area where the horizontal well to be predicted is located to obtain the predicted wellbore trajectory of the horizontal well to be predicted includes: selecting wellbore trajectories and logging data of a plurality of the drilled wells in the well area; Calculating the wellbore trajectory tortuosity of any reference logging section based on the wellbore trajectory and logging data of each of the drilled wells; Performing statistical analysis on the tortuosity of the wellbore trajectories of the plurality of drilled wells to determine a changing pattern of the wellbore trajectories; The preset wellbore trajectory is subjected to actual drilling processing according to the wellbore trajectory change law to obtain the predicted wellbore trajectory of the horizontal well to be predicted.

3. The method for designing the maximum length of the horizontal section of a horizontal well according to claim 2, characterized in that: The calculation characteristic parameter of the wellbore trajectory tortuosity is the wellbore curvature vector change rate. The calculation formula of the wellbore curvature vector change rate of the reference logging section is: ； Where, It refers to the change rate of the wellbore curvature vector of the i-th benchmark logging section, ; 、 are the average wellbore curvatures of the i-th benchmark logging section and the i+1-th benchmark logging section, respectively. ; is the angle between the normal direction of the plane where the i-th benchmark logging section and the i+1-th benchmark logging section are located, °; is the average length of the two logging sections, the i-th benchmark logging section and the i+1-th benchmark logging section, in m.

4. The method for designing the maximum length of the horizontal section of a horizontal well according to claim 3, characterized in that: The performing statistical analysis on the wellbore trajectory tortuosity of the plurality of drilled wells to determine the wellbore trajectory variation pattern includes: Calculating the standard deviation of the change rate of the wellbore curvature vector of each drilled well in the vertical well section, the deflection section and the horizontal section respectively; The standard deviations of multiple wells drilled in the same well section are weighted averaged to determine the change pattern of the wellbore trajectory.

5. The method for designing the maximum length of the horizontal section of a horizontal well according to claim 4, characterized in that: Performing actual drilling processing on the preset wellbore trajectory according to the wellbore trajectory change law to obtain the predicted wellbore trajectory of the horizontal well to be predicted includes: Generating a wellbore curvature vector change rate that conforms to a normal distribution and has an average value of 0 according to the weighted average standard deviation; The predicted wellbore trajectory is generated according to a preset correction formula, the wellbore curvature vector change rate, and the preset wellbore trajectory, wherein the preset correction formula is: ； Where, is the well inclination angle of the i-th point after correction, (°); is the well inclination angle of the i-th point before correction, (°); is the change rate of the wellbore curvature vector that conforms to the normal distribution, ; 、 are the lengths of the j-th and j-1-th benchmark logging sections, respectively.

6. The method for designing the maximum length of a horizontal section of a horizontal well according to any one of claims 1 to 5, characterized in that: The design method further includes: When the number of sweet spots and target points of the horizontal well to be predicted is more than three and they are not collinear, the horizontal section limit length of the horizontal well to be predicted needs to be subtracted from the horizontal section length converted from the multiple non-collinear target points.

7. The method for designing the maximum length of a horizontal section of a horizontal well according to any one of claims 1 to 5, characterized in that: The design method further includes: When the drilling fluid density of the horizontal well to be predicted does not meet the leakage constraint or the collapse constraint, drilling of the horizontal section is stopped.

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