Automated Downhole Geological Steering Method for Horizontal Drilling Based on Gamma-Ray Data While Drilling

Abstract

This invention belongs to the field of geological steering and geological exploration technology, and relates to an automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling. It aims to solve the problems of slow response, inefficient decision-making, and trajectory deviation in existing technologies. The invention includes: real-time acquisition of natural gamma-ray data and azimuth gamma-ray data from measurements while drilling; determining the relative position of the drill bit and the drilling rig at the current moment; acquiring the inclination angle and vertical depth of the drill bit at the current moment, and calculating and updating the formation dip angle based on the relative position; determining the angle difference based on the inclination angle and formation dip angle at the current moment; and adjusting the inclination angle of the next section of drilling footage according to the angle difference and the relative position of the drill bit for geological steering. This invention constructs an automated decision-making logic, resulting in a faster downhole response and enabling immediate adjustments under critical conditions such as the drill bit approaching the drilling rig boundary or excessive deviation between the inclination angle and the formation dip angle.

Description

Technical Field

[0001] This invention belongs to the field of geological guidance and geological exploration technology, and specifically relates to an automated method and system for downhole geological guidance in horizontal drilling based on gamma-ray data while drilling. Background Technology

[0002] In the field of unconventional oil and gas exploration and development, horizontal drilling technology is one of the core means to achieve efficient resource extraction. Its core objective is to ensure that the wellbore trajectory accurately traverses the reservoir "box" (i.e., the effective reservoir section), while simultaneously satisfying two key constraints: first, ensuring the box's penetration rate to avoid loss of effective reservoir due to trajectory deviation; and second, controlling the smoothness of the wellbore trajectory to adapt to the dogleg limitations of rotary steerable drill strings and provide favorable engineering conditions for subsequent fracturing operations, reducing the impact of large-angle bending on construction efficiency. Furthermore, the economic requirements of the drilling process must also be considered, requiring optimized decision-making processes to achieve rapid drilling completion and reduce time costs. Therefore, the core value of geosteering technology in horizontal drilling lies in: real-time acquisition of drill bit position information and dynamic adjustment of the drilling direction based on geological conditions, ensuring that the wellbore trajectory remains smoothly within the box, which is crucial for balancing penetration rate, trajectory quality, and drilling efficiency.

[0003] Currently, geological steering in horizontal drilling still relies primarily on manual decision-making. The typical workflow is as follows: during downhole drilling, measurement-while-drilling (MWD) equipment collects data and uploads it to the surface; surface technicians analyze the data, formulate drilling adjustment instructions, and then transmit them downhole for execution; the downhole drilling tools continue drilling according to these instructions. However, this model has significant limitations: there is a time delay in the transmission of data and instructions, and the manual analysis and decision-making process is time-consuming, resulting in a lag in the drill bit's response to formation changes. Under complex geological conditions, this lag can easily lead to risks such as the drill bit breaking out of the wellbore and the well trajectory deviating from the reservoir. Especially under critical conditions such as when the drill bit approaches the wellbore boundary or the well inclination angle does not match the formation dip angle, it may cause irreversible reservoir loss or increased engineering costs.

[0004] From a technical implementation perspective, due to limitations such as cost control, the geophysical logging methods commonly used in unconventional oil and gas horizontal drilling are relatively limited, mainly relying on natural gamma logging and azimuth gamma logging. Azimuth gamma logging often monitors upper and lower gamma data (i.e., the gamma ray intensity of the formation above and below the drill bit) to help determine formation lithology changes and the drill bit's position relative to the drilling box. However, existing manual decision-making models fail to fully utilize the real-time value of these logging data, making it difficult to achieve immediate optimization of the drilling direction.

[0005] Therefore, in response to the needs of unconventional oil and gas horizontal drilling and the current technological bottlenecks, it is of great significance to develop a downhole automated geological steering method based on real-time gamma data while drilling. Summary of the Invention

[0006] To address the aforementioned problems in existing technologies, namely, the lag in response, inefficient decision-making, and trajectory deviation in existing geological steering techniques, the first aspect of this invention proposes an automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling. This method achieves synergistic optimization of high hole-to-hole penetration rate, smooth trajectory, and efficient drilling during the geological steering process. The method includes the following steps:

[0007] Real-time acquisition of natural gamma data and azimuth gamma data from drilling measurements, wherein the azimuth gamma data includes upper gamma data and lower gamma data;

[0008] The natural gamma data and azimuth gamma data are compared with gamma formation features to determine the relative position of the drill bit and the box at the current moment. The gamma formation features are obtained by feature extraction from the natural gamma logging curve.

[0009] Obtain the current well inclination angle and drill bit vertical depth, and calculate and update the formation dip angle based on the relative position;

[0010] The angle difference is determined based on the current well inclination angle and formation dip angle. The well inclination angle of the next section of the drilling is adjusted according to the relative position of the drill bit and the angle difference to conduct geological guidance.

[0011] In some preferred embodiments, gamma-ray formation features are obtained by feature extraction from natural gamma-ray logging curves. The method is as follows:

[0012] Obtain the natural gamma logging curves of the formations in the box containing the target horizontal well and the upper and lower parts of the box.

[0013] The midpoint and each inflection point of each segment of the natural gamma logging curve are taken as feature points, and the range of natural gamma value variation of each feature point is extracted as the natural gamma feature at that feature point.

[0014] Extract the gamma value within a preset range above each feature point as the upper gamma data of that feature point, and the gamma value within a preset range below it as the lower gamma data of that feature point. Use the relative magnitude of the upper and lower gamma values ​​as the azimuth gamma feature of that feature point.

[0015] Extract the distance from each feature point to the upper interface of the box as the top surface distance at that feature point;

[0016] Gamma stratigraphic features are constructed based on the natural gamma features, azimuth gamma features, and top surface distance. The gamma stratigraphic features include the corresponding data and relationships of the natural gamma features, azimuth gamma features, and top surface distance.

[0017] In some preferred embodiments, the natural gamma data and azimuth gamma data are compared with gamma stratigraphic features to determine the relative position of the drill bit and the casing at the current moment. The method is as follows:

[0018] A1. Set the starting point of the actual drilling process, obtain the formation dip angle and well depth corresponding to the starting point based on the actual drilling fitting, compare with the gamma formation characteristics, and determine the characteristic point corresponding to the starting point.

[0019] A2. The feature point corresponding to the starting point is determined as the reference feature point of the first segment of advance, and the reference feature point includes the corresponding gamma feature.

[0020] A3. Control the drill bit to drill a certain length according to the preset instructions. For the advance length L, determine the midpoint of that advance length as the positioning point;

[0021] A4. Compare the actual gamma feature at the obtained positioning point with the gamma feature of the reference feature point:

[0022] If the actual gamma feature matches the gamma feature of the reference feature point, then the current well depth, well inclination, and actual feature point are output.

[0023] If the actual gamma feature does not conform to the gamma feature of the reference feature point, then determine whether it conforms to the gamma features of the adjacent feature points above and below the reference feature point:

[0024] If the actual gamma feature matches the gamma feature of adjacent feature points of the reference feature point, output the current well depth, well inclination and actual feature point;

[0025] If the actual gamma feature does not conform to the gamma feature of the adjacent feature points of the reference feature point, determine whether it conforms to the gamma feature of the remaining feature points, and output the well depth, well inclination and all feature points that conform to the actual gamma feature at this time as a reference for manual judgment. The actual feature point at the current positioning point is determined by manual judgment.

[0026] A5. After completing the positioning of the midpoint of the current advance, obtain the top surface distance of the positioning point based on the actual feature point at the positioning point, and use the actual feature point as the new reference feature point for positioning the midpoint of the next advance.

[0027] A6. The length of each drilling segment is... After L advances, repeat steps A3-A5, using the midpoint of the current advance as the positioning point, comparing it with the gamma feature of the reference feature point determined in the previous segment, and updating the reference feature point to achieve continuous positioning of the drill bit during actual drilling.

[0028] In some preferred embodiments, the actual gamma feature at the location point is obtained by:

[0029] Current segment advance length L is divided into three equal subintervals along the advance direction, resulting in three subintervals of equal length. The length of each subinterval is... L / 3;

[0030] The median of the natural gamma data, upper gamma data, and lower gamma data in the middle sub-interval is used as the gamma representative value of the natural gamma data, upper gamma data, and lower gamma data at the location point, i.e., the actual gamma feature.

[0031] In some preferred embodiments, the formation dip angle is calculated and updated as follows:

[0032] Obtain the vertical depth of the positioning point and the inclination angle of the starting point of this section of the advance. Project the positioning points of this section of the advance and the positioning points of the previous section of the advance onto the upper and lower interfaces of the box. Combine the current length of the advance, the distance from the top surface of the positioning point, and the updated formation dip angle of the previous section of the advance to analyze the geometric relationship and solve for the corresponding formation dip angle.

[0033] In some preferred embodiments, the well inclination angle of the next section of the drilling is adjusted for geological guidance, the method of which is as follows:

[0034] Based on the natural gamma logging curve, the central region of the box is selected as the optimal target region, and the central region is determined according to the center point of the box.

[0035] Determine the distance between the location of the feature point where the positioning point is located and the preset optimal target area. Based on the distance and angle difference, adjust the well inclination angle to control the drilling direction of the horizontal well and ensure that the horizontal well is drilled to the optimal target area.

[0036] The adjustment range of the well inclination angle shall not exceed the preset adjustment threshold.

[0037] A second aspect of this invention proposes an automated downhole geological steering system for horizontal drilling based on gamma-ray while drilling data, the system comprising:

[0038] The data acquisition module is configured to acquire natural gamma data and azimuth gamma data from drilling measurements in real time, wherein the azimuth gamma data includes upper gamma data and lower gamma data.

[0039] The positioning module is configured to compare the natural gamma and azimuth gamma data with gamma formation features to determine the relative position of the drill bit and the box at the current moment. The gamma formation features are obtained by feature extraction from the natural gamma logging curve.

[0040] The formation dip angle calculation module is configured to obtain the current well inclination angle and drill bit vertical depth, and calculate and update the formation dip angle based on the relative position.

[0041] The guidance module is configured to determine the angle difference based on the current well inclination angle and formation dip angle, and adjust the well inclination angle of the next section of the advance according to the relative position and angle difference to perform geological guidance.

[0042] The beneficial effects of this invention are:

[0043] This invention employs commonly used natural gamma and azimuth gamma logging-while-drilling (LOD) techniques to construct an automated decision-making logic, reducing the subjective errors of manual analysis. Simultaneously, through mechanisms such as dynamically updating benchmark feature points and real-time comparison of gamma features, drilling adjustments are made more closely aligned with actual formation changes, improving response timeliness. Besides measuring wellbore trajectory engineering parameters (well depth, vertical depth, inclination angle, etc.) during drilling, no other LOD equipment is required, thus eliminating additional economic costs. It retains surface monitoring and necessary manual intervention to avoid misjudgments and promptly adjust the drilling direction under critical conditions, ultimately achieving synergistic optimization of high drilling success rate, trajectory smoothness, and drilling efficiency.

[0044] Through the two main steps of "positioning" and "decision-making," the routine decision-making of geological steering engineers at the horizontal drilling site is reproduced and transferred to the downhole for automatic execution. This significantly shortens the time interval between obtaining formation information and drilling adjustments, effectively solving the response lag problem caused by data transmission and manual analysis in the traditional manual decision-making mode. This makes the downhole response faster and enables real-time adjustments under critical conditions such as when the drill bit approaches the box boundary or when the well inclination angle deviates too much from the formation dip angle. This optimizes decision-making accuracy, significantly reduces the risk of drilling out of the box, and ensures the adaptability of the trajectory to the project.

[0045] The automated decision-making process simultaneously considers the dogleg limitations of the rotary steerable drill string and the subsequent fracturing requirements. By smoothly adjusting the drilling direction to avoid large-angle bending, it ensures the engineering applicability of the wellbore trajectory and lays a good foundation for subsequent construction. It can achieve rapid drilling completion, reduce time costs and equipment wear, and indirectly increase oil and gas production due to the improved reservoir encounter rate, thus comprehensively improving the economic benefits of unconventional oil and gas horizontal drilling. Attached Figure Description

[0046] Other features, objects, and advantages of this application will become more apparent from the following detailed description of non-limiting embodiments with reference to the accompanying drawings:

[0047] Figure 1 This is a flowchart of an automated downhole geological steering method for horizontal drilling based on gamma-ray data during drilling, as described in this embodiment of the invention.

[0048] Figure 2 These are the vertical natural gamma variation curves of the formation within the box and in the upper and lower parts, obtained based on well logging curves in this embodiment of the invention.

[0049] Figure 3This is an embodiment of the present invention. Figure 2 Analysis diagram of the location gamma features at different feature points in the middle;

[0050] Figure 4 This is a trajectory diagram of the drill bit positioning during the actual drilling process in an embodiment of the present invention;

[0051] Figure 5 This is a schematic diagram illustrating the updating of formation dip angle and calculation of positioning point coordinates during drilling in an embodiment of the present invention;

[0052] Figure 6 This is a schematic diagram illustrating the calculation of the starting point coordinates of the trajectory during the drilling process in an embodiment of the present invention. Detailed Implementation

[0053] The present application will now be described in further detail with reference to the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are for illustrative purposes only and are not intended to limit the invention. Furthermore, it should be noted that, for ease of description, only the parts relevant to the invention are shown in the accompanying drawings.

[0054] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. This application will now be described in detail with reference to the accompanying drawings and embodiments.

[0055] This invention obtains gamma formation characteristics based on well logging curves, acquires natural gamma data and azimuth gamma data from drilling measurements in real time, determines the location by dynamically updating benchmark feature points and comparing gamma features in real time, and then calculates the formation dip angle and angle difference to provide geological guidance for drilling, ultimately achieving synergistic optimization of high drilling success rate, trajectory smoothness and drilling efficiency.

[0056] The automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data of the present invention includes the following steps:

[0057] Real-time acquisition of natural gamma data and azimuth gamma data from drilling measurements, wherein the azimuth gamma data includes upper gamma data and lower gamma data;

[0058] The natural gamma and azimuth gamma data are compared with gamma formation features to determine the relative position of the drill bit and the box at the current moment. The gamma formation features are obtained by feature extraction from the natural gamma logging curve.

[0059] Obtain the current well inclination angle and drill bit vertical depth, and calculate and update the formation dip angle based on the relative position;

[0060] The angle difference is determined based on the current well inclination angle and formation dip angle. The well inclination angle of the next section of the drilling is adjusted according to the relative position of the drill bit and the angle difference to conduct geological guidance.

[0061] To more clearly explain the automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data of the present invention, the following will be combined with... Figure 1 The steps in the embodiments of the present invention will be described in detail below.

[0062] The first embodiment of the automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling according to the present invention includes the following steps S1 to S4, each step of which is described in detail below:

[0063] S1. Real-time acquisition of natural gamma data and azimuth gamma data from drilling measurements, wherein the azimuth gamma data includes upper gamma data and lower gamma data.

[0064] Preferably, before acquiring data, the vertical natural gamma variation curves of the formation within the box and the upper and lower parts are obtained by fitting natural gamma logging curves.

[0065] S2. Compare the natural gamma and azimuth gamma data with the gamma formation features to determine the relative position of the drill bit and the box at the current moment. The gamma formation features are obtained by feature extraction from the natural gamma logging curve.

[0066] Preferably, gamma-ray formation characteristics are obtained by feature extraction from natural gamma-ray logging curves, and the method is as follows:

[0067] Obtain the natural gamma logging curves of the formations in the box containing the target horizontal well and the upper and lower parts of the box.

[0068] The midpoint and each inflection point of each segment of the natural gamma logging curve are taken as feature points, and the range of natural gamma value variation of each feature point is extracted as the natural gamma feature at that feature point.

[0069] Extract the gamma value within a preset range above each feature point as the upper gamma data of that feature point, and the gamma value within a preset range below it as the lower gamma data of that feature point. Use the relative magnitude of the upper and lower gamma values ​​as the azimuth gamma feature of that feature point.

[0070] Extract the distance from each feature point to the upper interface of the box as the top surface distance at that feature point;

[0071] Gamma stratigraphic features are constructed based on the natural gamma features, azimuth gamma features, and top surface distance. The gamma stratigraphic features include the corresponding data and relationships of the natural gamma features, azimuth gamma features, and top surface distance.

[0072] More preferably, the feature point at the midpoint of each segment represents that segment, and the feature point at the inflection point represents only that point; when the natural gamma and azimuth gamma features of adjacent feature points are the same, they are merged into one feature point.

[0073] More preferably, the range of variation of the natural gamma value of each feature point is the range of variation of the gamma value within a preset range above and below each feature point. In this embodiment, the maximum and minimum values ​​of the natural gamma value within the preset range are taken as the natural gamma feature at that feature point.

[0074] More preferably, the average of the natural gamma values ​​within a preset range above each feature point is extracted as the upper gamma value of the feature point, and the average of the natural gamma values ​​within a preset range below each feature point is extracted as the lower gamma value of the feature point.

[0075] During actual drilling, due to factors such as formation inhomogeneity, vibrations during drilling, and instrument errors, even if the relative position of the drill bit and the drilling housing remains constant, the measured gamma-ray data will still fluctuate within a certain range. Therefore, the drill bit position cannot be determined based on a single gamma-ray measurement; it is necessary to determine the position based on a certain amount of drilling footage (length). The data from L) are used to make a comprehensive judgment.

[0076] Preferably, the relative position of the drill bit and the housing at the current moment is determined by comparing the natural gamma and azimuth gamma data with gamma stratigraphic features. The method is as follows:

[0077] A1. Set the starting point of the actual drilling process, obtain the formation dip angle and well depth corresponding to the starting point based on the actual drilling fitting, compare with the gamma formation characteristics, and determine the characteristic point corresponding to the starting point.

[0078] A2. The feature point corresponding to the starting point is determined as the reference feature point of the first segment of advance, and the reference feature point includes the corresponding gamma feature.

[0079] A3. Control the drill bit to drill a certain length according to the preset instructions. For the advance length L, determine the midpoint of that advance length as the positioning point;

[0080] A4. Compare the actual gamma feature at the obtained positioning point with the gamma feature of the reference feature point:

[0081] If the actual gamma feature matches the gamma feature of the reference feature point, then the current well depth, well inclination, and actual feature point are output.

[0082] If the actual gamma feature does not conform to the gamma feature of the reference feature point, then determine whether it conforms to the gamma features of the adjacent feature points above and below the reference feature point:

[0083] If the actual gamma feature matches the gamma feature of adjacent feature points of the reference feature point, output the current well depth, well inclination and actual feature point;

[0084] If the actual gamma feature does not conform to the gamma feature of the adjacent feature points of the reference feature point, determine whether it conforms to the gamma feature of the remaining feature points, and output the well depth, well inclination and all feature points that conform to the actual gamma feature at this time as a reference for manual judgment. The actual feature point at the current positioning point is determined by manual judgment.

[0085] A5. After completing the positioning of the midpoint of the current advance, obtain the top surface distance of the positioning point based on the actual feature point at the positioning point, and use the actual feature point as the new reference feature point for positioning the midpoint of the next advance.

[0086] A6. The length of each drilling segment is... After L advances, repeat steps A3-A5, using the midpoint of the current advance as the positioning point, comparing it with the gamma feature of the reference feature point determined in the previous segment, and updating the reference feature point to achieve continuous positioning of the drill bit during actual drilling.

[0087] More preferably, the gamma features of the reference feature point include the natural gamma features and the azimuth gamma features of the reference feature point.

[0088] More preferably, the method for obtaining the actual gamma feature at the positioning point is as follows:

[0089] Current segment advance length L is divided into three equal subintervals along the advance direction, resulting in three subintervals of equal length. The length of each subinterval is... L / 3;

[0090] The median of the natural gamma data, upper gamma data, and lower gamma data in the middle sub-interval is used as the gamma representative value of the natural gamma data, upper gamma data, and lower gamma data at the location point, respectively, which is the actual gamma feature.

[0091] During horizontal drilling, it is often only necessary to adjust the drill bit's drilling angle, i.e., the well inclination angle, in the vertical direction, without needing to adjust the drill bit's azimuth in the horizontal direction. Therefore, it is only necessary to calculate the change in the formation dip angle within the vertical plane along the drilling trajectory. After drilling a certain distance ∆L, the characteristic point number of the current positioning point can be obtained through the aforementioned "positioning" process.

[0092] S3. Obtain the current well inclination angle and drill bit vertical depth, and calculate and update the formation dip angle based on the relative position. The method is as follows:

[0093] Obtain the vertical depth of the positioning point and the inclination angle of the starting point of this section of the advance. Project the positioning points of this section of the advance and the positioning points of the previous section of the advance onto the upper and lower interfaces of the box. Combine the current length of the advance, the distance from the top surface of the positioning point, and the updated formation dip angle of the previous section of the advance to analyze the geometric relationship and solve for the corresponding formation dip angle.

[0094] S4. Determine the angle difference based on the well inclination angle and formation dip angle at the starting point of this section of footage. Adjust the well inclination angle of the next section of footage according to the relative position and angle difference, and carry out geological guidance.

[0095] Preferably, the method for adjusting the inclination angle of the lower section of the wellbore for geological guidance is as follows:

[0096] Based on the natural gamma logging curve, the central region of the box is selected as the optimal target region, and the central region is determined according to the center point of the box.

[0097] Determine the distance between the location of the feature point where the positioning point is located and the preset optimal target area. Based on the distance and angle difference, adjust the well inclination angle to control the drilling direction of the horizontal well and ensure that the horizontal well is drilled to the optimal target area.

[0098] The adjustment range of the well inclination angle shall not exceed the preset adjustment threshold.

[0099] Preferably, the central region is determined based on the center point of the box. In this embodiment, the central region is selected as the region of several feature points closest to the center point within the neighborhood of the center point. The feature point region is a preset range area above and below the feature point.

[0100] More preferably, the three feature point regions closest to the center point within the neighborhood of the center point are selected as the center region.

[0101] Preferably, after obtaining the dip angle of the strata, the two-dimensional coordinates of the positioning point and its projection points on the upper and lower interfaces of the box are calculated in the vertical plane, taking into account the vertical thickness of the box. The method is as follows:

[0102] Using the projection point of the starting point onto the upper interface of the box as the origin of the coordinate system, the geometric relationship is analyzed based on the coordinates of the upper section's advance positioning point, and the coordinates of the current section's advance positioning point and its projection onto the upper and lower interfaces of the box are obtained.

[0103] During actual drilling, the real-time coordinates of the drill bit and its projection points on the upper and lower interfaces of the drilling rig, the well depth of the positioning point, the well inclination and the corresponding feature points, the formation dip angle, and the decision information based on gamma feature comparison are transmitted to the well monitoring terminal. The well monitoring terminal is used for real-time monitoring by humans. When an abnormal situation is detected, manual intervention can be carried out by issuing instructions through the well terminal, including pausing drilling, adjusting the footage length, or recalibrating the reference feature points.

[0104] More preferably, the abnormal situations include: the actual gamma feature at the positioning point does not match the gamma feature of the reference feature point and its two adjacent feature points; the real-time coordinate display transmitted to the well shows that the drill bit deviates from the box by ≥0.5 meters; and the formation dip angle changes abruptly by ≥3°.

[0105] Preferably, in this embodiment, the automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data controls the horizontal drilling to be advanced at a certain location. The method is as follows:

[0106] First, obtain the natural gamma logging curve, such as Figure 2 As shown, feature extraction is performed to obtain gamma-ray stratigraphic features. The specific steps are as follows:

[0107] 1) Using the midpoint and inflection points of each segment of the gamma curve as feature points, extract the range of natural gamma values ​​as the natural gamma feature at that point. The feature point at the midpoint of each segment represents that segment. For example, at feature point 7, the natural gamma value range is... gr 7 L - gr 7 H The feature points at the inflection points only represent that point; for example, the natural gamma value of feature point 8 is... gr 8 .

[0108] 2) In addition to natural gamma features, it is also necessary to extract azimuth gamma features at each feature point, such as... Figure 3 As shown, at feature point 10, upper gamma equals lower gamma; at feature point 11, upper gamma < lower gamma; and at feature point 13, upper gamma > lower gamma. Note that the inflection point between feature points 7 and 8 was not extracted as a feature point because the natural gamma value at this inflection point falls within the natural gamma range of feature point 7, and its upper and lower gamma features are the same as those of feature point 7. Therefore, the feature point is not repeated here.

[0109] 3) Calculate the distance from each feature point to the upper interface of the box. d For example, the distance from feature point 8 to the upper interface of the box is d 8 In this embodiment, when the feature point is above the upper interface of the box, d The value is negative; when the feature point is below the upper interface of the box, d It is positive.

[0110] The gamma-stratigraphic characteristics of each feature point are shown in Table 1.

[0111] Table 1. Gamma-stratigraphic characteristics of feature points

[0112]

[0113] Second, real-time acquisition of natural gamma and azimuth gamma data from drilling measurements is used to determine the relative position of the drill bit and the hull. The specific steps are as follows:

[0114] 1) After the drill bit enters the housing, set a starting point.D 0 The dip angle of the strata here α 0 The well depth has been obtained from actual drilling fitting. L Based on natural gamma data and azimuth gamma data, it was clearly determined that the starting point was located at a feature point. n At this feature point n This is the reference feature point for the next section of advance.

[0115] 2) Drill a section of the tunnel. L Then, the midpoint of this advance section is used as the positioning point. D 1 Determine whether the gamma feature at the location point still conforms to the reference feature point. n Features:

[0116] If the conditions are met, output the current well depth. L +1 / 2 L ), well deviation θ and feature point number n ;

[0117] If it does not meet the requirement, then another feature point is evaluated both upwards and downwards, i.e., it is determined whether the current gamma feature meets the feature point requirement. n-1 ) and feature points ( n+1 Characteristics of )

[0118] If the conditions are met, output the well depth, well inclination, and feature points at this time;

[0119] If it still does not meet the requirements, then judge all the remaining feature points separately, and output the well depth, well inclination and the numbers of all matching feature points at this time as a reference for manual judgment.

[0120] After testing, the location point D 1 Conforms to the reference feature point n Thus, the first section of advance after the starting point... L The trajectory "location" at the midpoint has been completed. The well depth at this point is ( ). L+1 / 2 L ), well inclination is θ The drill bit is located at the feature point identified in the above steps.

[0121] 3) Obtain the location point D 1 After identifying the feature point number, the location point is obtained. D 1 Distance from the upper interface of the box d .

[0122] 4) Location point at this time D 1 The corresponding feature points become the new reference feature points for "locating" the midpoint of the next drilling segment; as drilling continues, each segment... L Performing this check after each advance ensures proper positioning of the drill bit during actual drilling (as shown in the attached figure). Figure 4 ).

[0123] Third, based on the current location point D 2 and a certain site D 1 By identifying the feature point number, the dip angle between these two points can be updated. The specific steps are as follows:

[0124] As attached Figure 5 At the current location point D 2 and a certain site D 1 Draw a vertical line at point [location], and its intersection with the upper interface of the box is [point]. S 1 , S 2 The point is the intersection of the point and the lower interface of the box. S′ 1 , S′ 2 By analyzing the geometric relationships, we can obtain the following:

[0125] ;

[0126] ;

[0127] ;

[0128] ;

[0129] ;

[0130] in, d 1 , d 2 These are obtained during the positioning process. D 1 , D 2 The distance between the point and the top of the box; α 1 For a certain site D 1 The corresponding dip angle of the strata, α 2 for S1 and S 2 The dip angle of the strata between the points (unknown at this time, needs to be calculated); β This is the starting point of this advance, i.e., the trajectory. D 1 D 2 The well inclination angle at the midpoint can be obtained through MWD or LWD and used to represent... D 1 D 2 The average well inclination angle of the section; D 1 , D 2 Vertical depth at point TVD 1 and TVD 2 It can be obtained from MWD or LWD during drilling;

[0131] In the above formula, only the dip angle of the formation is considered. α 2 If the unknown quantity is a variable, it can be obtained by solving the equation. α 2 That is S 1 and S 2 The dip angle of the strata between them.

[0132] Fourth, the upper certain position is known. D 1 coordinates ( x D1 ,y D1 ) and the corresponding upper interface of the box. S 1 Point coordinates ( x S1 , y S1 ), the lower interface of the box S′ 1 Point coordinates ( x′ S1 ,y′ S1 ), based on the above fixed site D 1 coordinates ( x D1 ,y D1 ), calculate the current location point D 2 coordinates ( x D2 ,yD2 ), Analyzing the geometric relationships yields:

[0133] ;

[0134] ;

[0135] The corresponding interface on the box S 2 Point coordinates ( x S2 ,y S2 )for:

[0136] ;

[0137] ;

[0138] Due to the thickness of the box d box It is often assumed to remain unchanged, hence the point. D 2 Projection on the lower interface of the box S′ 2 The coordinates of the point are:

[0139] ;

[0140] ;

[0141] Therefore, based on the coordinates of the previous fixed point, the coordinates of the current positioning point and the corresponding upper and lower interfaces of the box can be calculated.

[0142] Fifth, based on the drill bit positioning results and the difference between the formation dip angle and the well inclination angle (angle difference), adjust the well inclination angle for the next drilling step. The specific steps are as follows:

[0143] Select a suitable feature point area within the box as the optimal area based on the actual situation of the project. If the drill bit is far from the optimal area, adjust the angle by a large angle; if the distance is close, adjust the angle by a small angle; if it is within the optimal area, make fine adjustments or do not adjust according to the angle difference.

[0144] Preferably, in this embodiment, the attached... Figure 1 The 8, 9, 10, and 11 feature point regions in the middle of the central housing are selected as the optimal region; the current well inclination angle is... θ angular difference γ =Structuration dip angle α -Well inclination angle θ.If the current positioning point is far from the optimal area (located at feature points 1-5 or 14-15), then adjust the well inclination angle to the level of drilling along the formation (θ+γ), and then back down by 2°. That is, if located at feature point 1-5, the well inclination angle needs to be reduced to bring the drill bit closer to the optimal area. In this case, the well inclination angle is adjusted to ( ). θ+ γ-2 If the location is at feature point 14-15, the well inclination angle needs to be increased to bring the drill bit closer to the optimal area. The well inclination angle should then be adjusted to ( ). θ+γ+2 If the current positioning point is close to the optimal area (located at feature points 6-7 or 12-13), the well inclination angle is adjusted to bevel drilling, then adjusted back by 1°. If the current positioning point is within the optimal area (located at feature points 8-11) and the angle difference is greater than 0.5°, the well inclination angle is adjusted to bevel drilling. If the angle difference is less than or equal to 0.5°, no adjustment is made. To avoid decision-making errors caused by misjudging the location of the current positioning point, if two consecutive positioning points are not within the optimal area, a large or small angle adjustment is made according to the aforementioned principle. If there is only one instance of the point being outside the optimal area, no adjustment is made to avoid adjustment errors caused by misjudgment. If both points are within the optimal area, adjustments are made based on the angle difference. The next drilling decision is shown in Table 2.

[0145] Table 2 Drilling Decision

[0146]

[0147] Preferably, as long as the coordinates of the starting point are known, the coordinates of subsequent positioning points can all be calculated. In this embodiment, the starting point of the drilling trajectory is... D 0 The projection point on the top of the box S 0 As the origin of the coordinate system, D 0 The coordinates of a point are calculated as follows:

[0148] Setting the trajectory start point D 0 At that time, the dip angle of the strata α 0 The location has been obtained through actual drilling and fitting, and the feature point numbers representing its position have also been determined. Therefore, its distance from the upper interface of the box is... d 0 Also known; based on drilling MWD or LWD, it can be obtained D 0 The vertical depth of the point is TVD0. Therefore... D 0 The coordinates are:

[0149] ;

[0150] ;

[0151] After obtaining the coordinates of each positioning point and its projection points on the upper and lower interfaces of the box, this coordinate information can be transmitted to the manual monitoring platform on the well. As the drilling process progresses, the top and bottom interfaces of the box and the drilling trajectory are gradually drawn. If any abnormality is found, the program judgment is stopped in time, the feature point number judged manually and the next step instruction are input into the program, and then the program is started to perform the next judgment.

[0152] Preferably, since the trajectory may be adjusted with a certain degree of dog-leg curvature, the trajectory D 1 D 2 It is not necessarily a straight line, so in this embodiment, the inclination angle at the midpoint is used to represent the inclination angle of this segment.

[0153] Preferably, during the "localization" process, it is allowed to search for a feature point upwards or downwards based on the feature point of the previous localization point to obtain the feature point number of the current localization point. At this time, the program may misjudge, causing the localization result of the current localization point to deviate from the feature point by 1 feature point (generally, it will not deviate from 2 feature points or more; if the deviation is too large, it will be impossible to find a feature point that matches the gamma feature of the localization point, and a manual intervention mechanism will be activated).

[0154] More preferably, since the directional drilling capability of the rotary guide device is limited, such as 5° / 30m, that is, the well inclination angle can be adjusted by a maximum of 5° during the drilling process of 30m, when making a decision, it is required that the difference between the adjusted well inclination angle and the current well inclination angle shall not exceed the directional drilling capability of the instrument, and the current instruction should be issued after drilling a certain distance (such as 30m) or more after the previous instruction to adjust the well inclination angle is issued.

[0155] Although the steps in the above embodiments are described in the above order, those skilled in the art will understand that in order to achieve the effect of this embodiment, different steps do not need to be executed in such an order. They can be executed simultaneously (in parallel) or in a reverse order. These simple variations are all within the protection scope of this invention.

[0156] A second embodiment of the present invention provides an automated downhole geological steering system for horizontal drilling based on gamma-ray while drilling data, the system comprising:

[0157] The data acquisition module is configured to acquire natural gamma data and azimuth gamma data from drilling measurements in real time, wherein the azimuth gamma data includes upper gamma data and lower gamma data.

[0158] The positioning module is configured to compare the natural gamma and azimuth gamma data with gamma formation features to determine the relative position of the drill bit and the box at the current moment. The gamma formation features are obtained by feature extraction from the natural gamma logging curve.

[0159] The formation dip angle calculation module is configured to obtain the current well inclination angle and the vertical depth of the drill bit, calculate and update the formation dip angle based on the relative position, and determine the two-dimensional coordinates of the drill bit in the vertical plane based on the formation dip angle and the current drilling length.

[0160] The guidance module is configured to determine the angle difference based on the current well inclination angle and formation dip angle, and adjust the well inclination angle of the next section of the advance according to the relative position and angle difference to perform geological guidance.

[0161] It should be noted that the automated downhole geological steering system for horizontal drilling based on gamma-ray data during drilling provided in the above embodiments is only an example of the division of the above functional modules. In practical applications, the above functions can be assigned to different functional modules as needed, that is, the modules or steps in the embodiments of the present invention can be further decomposed or combined. For example, the modules in the above embodiments can be merged into one module, or further divided into multiple sub-modules to complete all or part of the functions described above. The names of the modules and steps involved in the embodiments of the present invention are only for distinguishing the various modules or steps and are not considered as an improper limitation of the present invention.

[0162] Those skilled in the art will understand that, for the sake of convenience and brevity, the specific working process and related descriptions of the system described above can be found in the corresponding processes in the foregoing method embodiments, and will not be repeated here.

[0163] A third embodiment of the present invention provides an automated downhole geological steering device for horizontal drilling based on gamma-ray while drilling data, comprising:

[0164] At least one processor; and

[0165] A memory communicatively connected to at least one of the processors; wherein,

[0166] The memory stores instructions that can be executed by the processor to implement the aforementioned automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling.

[0167] A fourth embodiment of the present invention provides a computer-readable storage medium storing computer instructions for execution by a computer to implement the above-described automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling.

[0168] Those skilled in the art will understand that, for the sake of convenience and brevity, the specific working process and related descriptions of the electronic device and computer-readable storage medium described above can be referred to the corresponding processes in the foregoing method embodiments, and will not be repeated here.

[0169] Those skilled in the art will recognize that the modules and method steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, computer software, or a combination of both. The programs corresponding to the software modules and method steps can be placed in random access memory (RAM), main memory, read-only memory (ROM), electrically programmable ROM, electrically erasable programmable ROM, registers, hard disks, removable disks, CD-ROMs, or any other form of storage medium known in the art. To clearly illustrate the interchangeability of electronic hardware and software, the components and steps of the various examples have been generally described in terms of functionality in the foregoing description. Whether these functions are implemented in electronic hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of the invention.

[0170] Computer program code for performing the operations of this application can be written in one or more programming languages ​​or a combination thereof, including object-oriented programming languages ​​such as Java, Smalltalk, and C++, and conventional procedural programming languages ​​such as the "C" language or similar programming languages. The program code can be executed entirely on the user's computer, partially on the user's computer, as a standalone software package, partially on the user's computer and partially on a remote computer, or entirely on a remote computer or server. In cases involving remote computers, the remote computer can be connected to the user's computer via any type of network—including a local area network (LAN) or a wide area network (WAN)—or can be connected to an external computer (e.g., via the Internet using an Internet service provider).

[0171] The flow charts and block diagrams in the accompanying drawings illustrate the possible architecture, functions and operations of the systems, methods and computer program products according to various embodiments of the present application. In this regard, each box in the flow chart or block diagram can represent a module, program segment or a part of code, and the module, program segment or a part of code contains one or more executable instructions for realizing the specified logical function. It should also be noted that in some alternative implementations, the functions marked in the box can also occur in a different order than that marked in the accompanying drawings. For example, two boxes represented in succession can actually be executed substantially in parallel, and they can sometimes be executed in the opposite order, depending on the functions involved. It should also be noted that each box in the block diagram and / or flow chart, and the combination of the boxes in the block diagram and / or flow chart can be implemented by a dedicated hardware-based system that performs the specified function or operation, or can be implemented by a combination of dedicated hardware and computer instructions.

[0172] The terms “first”, “second”, etc., are used to distinguish similar objects, not to describe or indicate a specific order or sequence.

[0173] The term "comprising" or any other similar term is intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus / device that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent in such process, method, article, or apparatus / device.

[0174] The technical solution of the present invention has been described above with reference to the preferred embodiments shown in the accompanying drawings. However, it will be readily understood by those skilled in the art that the scope of protection of the present invention is obviously not limited to these specific embodiments. Without departing from the principles of the present invention, those skilled in the art can make equivalent changes or substitutions to the relevant technical features, and the technical solutions after these changes or substitutions will all fall within the scope of protection of the present invention.

Claims

1. An automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data, characterized in that, Includes the following steps: Real-time acquisition of natural gamma data and azimuth gamma data from drilling measurements, wherein the azimuth gamma data includes upper gamma data and lower gamma data; The natural gamma data and azimuth gamma data are compared with gamma formation features to determine the relative position of the drill bit and the box at the current moment; the gamma formation features are obtained by feature extraction from the natural gamma logging curves, and the method is as follows: Obtain the natural gamma logging curves of the formations in the box containing the target horizontal well and the upper and lower parts of the box. The midpoint and each inflection point of each segment of the natural gamma logging curve are taken as feature points, and the range of natural gamma value variation of each feature point is extracted as the natural gamma feature at that feature point. Extract the gamma value within a preset range above each feature point as the upper gamma data of that feature point, and the gamma value within a preset range below it as the lower gamma data of that feature point. Use the relative magnitude of the upper and lower gamma values ​​as the azimuth gamma feature of that feature point. Extract the distance from each feature point to the upper interface of the box as the top surface distance at that feature point; Gamma stratigraphic features are constructed based on the natural gamma features, azimuth gamma features, and top surface distance. The gamma stratigraphic features include the corresponding data and relationships of the natural gamma features, azimuth gamma features, and top surface distance. Obtain the current well inclination angle and drill bit vertical depth, and calculate and update the formation dip angle based on the relative position; The angle difference is determined based on the current well inclination angle and formation dip angle. The well inclination angle of the next section of the drilling is adjusted according to the relative position of the drill bit and the angle difference to conduct geological guidance.

2. The automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling according to claim 1, characterized in that, The feature point at the midpoint of each segment represents that segment, and the feature point at the inflection point represents only that point; when the natural gamma and azimuth gamma features of adjacent feature points are the same, they are merged into one feature point.

3. The automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data according to claim 1, characterized in that, The average of the natural gamma values ​​within a preset range above each feature point is extracted as the upper gamma value of that feature point, and the average of the natural gamma values ​​within a preset range below each feature point is extracted as the lower gamma value of that feature point.

4. The automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling according to claim 1, characterized in that, The relative positions of the drill bit and the housing during drilling measurements are determined by comparing the natural gamma and azimuth gamma data with gamma formation characteristics. A1. Set the starting point of the actual drilling process, obtain the formation dip angle and well depth corresponding to the starting point based on the actual drilling fitting, compare with the gamma formation characteristics, and determine the characteristic point corresponding to the starting point. A2. The feature point corresponding to the starting point is determined as the reference feature point of the first segment of advance, and the reference feature point includes the corresponding gamma feature. A3. Control the drill bit to drill a certain length according to the preset instructions. For the advance length L, determine the midpoint of that advance length as the positioning point; A4. Compare the actual gamma feature at the obtained positioning point with the gamma feature of the reference feature point: If the actual gamma feature matches the gamma feature of the reference feature point, then the current well depth, well inclination, and actual feature point are output. If the actual gamma feature does not conform to the gamma feature of the reference feature point, then determine whether it conforms to the gamma features of the adjacent feature points above and below the reference feature point: If the actual gamma feature matches the gamma feature of adjacent feature points of the reference feature point, output the current well depth, well inclination and actual feature point; If the actual gamma feature does not conform to the gamma feature of the adjacent feature points of the reference feature point, determine whether it conforms to the gamma feature of the remaining feature points, and output the well depth, well inclination and all feature points that conform to the actual gamma feature at this time as a reference for manual judgment. The actual feature point at the current positioning point is determined by manual judgment. A5. After completing the positioning of the midpoint of the current advance, obtain the top surface distance of the positioning point based on the actual feature point at the positioning point, and use the actual feature point as the new reference feature point for positioning the midpoint of the next advance. A6. The length of each drilling segment is... After L advances, repeat steps A3-A5, using the midpoint of the current advance as the positioning point, comparing it with the gamma feature of the reference feature point determined in the previous segment, and updating the reference feature point to achieve continuous positioning of the drill bit during actual drilling.

5. The automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling according to claim 4, characterized in that, The gamma features of the reference feature point include the natural gamma features and the azimuth gamma features of the reference feature point.

6. The automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling according to claim 4, characterized in that, The method for obtaining the actual gamma feature at the location point is as follows: Current segment advance length L is divided into three equal subintervals along the advance direction, resulting in three subintervals of equal length. The length of each subinterval is... L / 3; The median of the natural gamma data, upper gamma data, and lower gamma data in the middle sub-interval is used as the gamma representative value of the natural gamma data, upper gamma data, and lower gamma data at the location point, i.e., the actual gamma feature.

7. The automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data according to claim 4, characterized in that, The method for calculating and updating the formation dip angle is as follows: Obtain the vertical depth of the positioning point and the inclination angle of the starting point of this section of the advance. Project the positioning points of this section of the advance and the positioning points of the previous section of the advance onto the upper and lower interfaces of the box. Combine the current length of the advance, the distance from the top surface of the positioning point, and the updated formation dip angle of the previous section of the advance to analyze the geometric relationship and solve for the corresponding formation dip angle.

8. The automated downhole geological steering method for horizontal drilling based on gamma-ray data while drilling according to claim 4, characterized in that, Adjusting the inclination angle of the next section of the wellbore for geological guidance is achieved through the following method: Based on the natural gamma logging curve, the central region of the box is selected as the optimal target region, and the central region is determined according to the center point of the box. Determine the distance between the location of the feature point where the positioning point is located and the preset optimal target area. Based on the distance and angle difference, adjust the well inclination angle to control the drilling direction of the horizontal well and ensure that the horizontal well is drilled to the optimal target area. The adjustment range of the well inclination angle shall not exceed the preset adjustment threshold.

9. An automated downhole geological steering system for horizontal drilling based on gamma-ray while drilling data, used to implement the automated downhole geological steering method for horizontal drilling based on gamma-ray while drilling data as described in any one of claims 1-8, characterized in that, The system includes: The data acquisition module is configured to acquire natural gamma data and azimuth gamma data from drilling measurements in real time, wherein the azimuth gamma data includes upper gamma data and lower gamma data. The positioning module is configured to compare the natural gamma and azimuth gamma data with gamma formation features to determine the relative position of the drill bit and the box at the current moment. The gamma formation features are obtained by feature extraction from the natural gamma logging curve. The formation dip angle calculation module is configured to obtain the current well inclination angle and drill bit vertical depth, and calculate and update the formation dip angle based on the relative position. The guidance module is configured to determine the angle difference based on the current well inclination angle and formation dip angle, and adjust the well inclination angle of the next section of the advance according to the relative position and angle difference to perform geological guidance.

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