Horizontal drilling underground geosteering automation method based on while-drilling gamma data

Abstract

The invention belongs to the technical field of geosteering and geological exploration, relates to a horizontal drilling underground geosteering automation method based on while-drilling gamma data, and aims to solve the problems of response lag, low decision efficiency and trajectory deviation in the prior art. The method comprises the following steps: acquiring natural gamma data and azimuth gamma data measured while drilling in real time; determining the relative position of the drill bit and the box body at the current moment; acquiring a hole drift angle at the current moment and the vertical depth of a drill bit, and calculating and updating a stratigraphic dip angle in combination with the relative position; and determining an angular difference based on the hole drift angle and the stratigraphic dip angle at the current moment, and adjusting the hole drift angle of the lower-section footage according to the angular difference and the relative position of the drill bit to carry out geosteering. Automatic decision logic is constructed, downhole response is quicker, and immediate adjustment can be achieved under critical working conditions that a drill bit is close to the boundary of a box body, and deviation between a hole drift angle and a stratigraphic dip angle is too large.

Description

Technical Field

[0001] The present invention belongs to the technical field of geosteering and geological exploration, and in particular relates to an automated method and system for downhole geosteering in horizontal drilling based on gamma-ray data while drilling. Background Art

[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 goal is to ensure that the wellbore trajectory accurately traverses the reservoir "box" (i.e., the effective reservoir section) while meeting two key constraints: first, to ensure the box penetration rate and avoid effective reservoir loss due to trajectory deviation; second, to control the smoothness of the wellbore trajectory to meet the dogleg degree limit of the rotary steerable drill bit, provide good engineering conditions for subsequent fracturing operations, and reduce the impact of large-angle bends on operation efficiency. Furthermore, the economic requirements of the drilling process must also be considered, and the decision-making process must be optimized to achieve rapid 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, dynamic adjustment of drilling direction based on geological conditions, and ensuring that the wellbore trajectory always remains smoothly within the box. This is the key to balancing the penetration rate, trajectory quality, and drilling efficiency. Currently, geosteering for horizontal drilling is still primarily based on manual decision-making. The typical workflow is as follows: During downhole drilling, measurement while drilling equipment collects data and uploads it to the surface; surface technicians analyze the data and formulate drilling adjustment instructions, which are then transmitted downhole for execution; and the downhole drill tool continues drilling according to the instructions. However, this model has significant limitations: there is a time delay in the up-and-down 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 drilling out of the casing and the wellbore trajectory deviating from the reservoir. This is especially true under critical operating conditions, such as when the drill bit approaches the casing boundary or the well inclination angle does not match the formation dip. This can cause irreparable reservoir loss or increased engineering costs. From a technical implementation perspective, due to cost constraints and other factors, the commonly used geophysical logging while drilling (LWD) methods in unconventional oil and gas horizontal drilling are relatively limited, relying primarily on natural gamma logging and azimuthal gamma logging. Azimuthal gamma logging typically monitors upper and lower gamma data (i.e., gamma ray intensity in the formation above and below the drill bit) to assist in determining formation lithologic variations and the drill bit's position relative to the drilling casing. However, existing manual decision-making models fail to fully utilize the real-time value of this logging data, making it difficult to achieve immediate optimization of drilling direction. Therefore, in response to the needs of unconventional oil and gas horizontal drilling and the existing technical bottlenecks, it is of great significance to develop a downhole automated geosteering method based on real-time gamma-ray data while drilling. Summary of the Invention

[0003] To address the aforementioned problems in the prior art, namely, the problems of delayed response, inefficient decision-making, and trajectory deviation in existing geosteering technologies, the present invention, in its first aspect, proposes an automated downhole geosteering method for horizontal drilling based on gamma-ray data while drilling, which achieves coordinated optimization of a high box encounter rate, smooth trajectory, and efficient drilling during geosteering. The method comprises the following steps: Real-time acquisition of natural gamma data and azimuthal gamma data of measurement while drilling, wherein the azimuthal gamma data includes upper gamma data and lower gamma data; Comparing the natural gamma ray data and the azimuthal gamma ray data with the gamma ray formation characteristics to determine the relative position of the drill bit and the casing at the current moment, wherein the gamma ray formation characteristics are obtained by extracting features from the natural gamma ray logging curve; Obtaining the well 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 positions; The angle difference is determined based on the well inclination angle and formation dip angle at the current moment, and the well inclination angle of the lower segment footage is adjusted according to the relative position of the drill bit and the angle difference to perform geosteering.

[0004] In some preferred embodiments, gamma formation characteristics are obtained by extracting features from natural gamma logging curves, and the method is as follows: Obtain the vertical natural gamma ray logging curve of the formation in the box where the target horizontal well is located and in the upper and lower parts of the box; Taking the midpoint of each section and each inflection point of the natural gamma logging curve as a feature point, and extracting the variation range of the natural gamma value of each feature point as the natural gamma feature at the feature point; Extract the gamma value within the preset range above each feature point as the upper gamma data of the feature point, and the gamma value within the preset range below the feature point as the lower gamma data of the feature point. The relative size relationship between the upper and lower gamma values ​​is used as the azimuth gamma feature of the feature point. Extract the distance from each feature point to the upper interface of the box as the top surface distance at the feature point; A gamma formation feature is constructed based on the natural gamma ray feature, the azimuthal gamma ray feature, and the top surface distance. The gamma formation feature includes corresponding data and correlation relationships of the natural gamma ray feature, the azimuthal gamma ray feature, and the top surface distance.

[0005] In some preferred embodiments, the natural gamma data and the azimuthal gamma data are compared with the gamma formation characteristics to determine the relative position of the drill bit and the casing at the current moment, and the method is as follows: A1. Set the starting point of the actual drilling process, obtain the formation inclination and well depth corresponding to the starting point based on the actual drilling fitting, compare them with the gamma formation characteristics, and determine the characteristic point corresponding to the starting point; A2. Determine the feature point corresponding to the starting point as the reference feature point of the first segment of footage, wherein the reference feature point includes a corresponding gamma feature; A3. Control the drill bit to drill a length of The footage of L, determine the midpoint of this footage as the positioning point; A4. Compare the actual gamma feature obtained at the 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, output the current corresponding well depth, well deviation and actual feature point; If the actual gamma feature does not conform to the gamma feature of the reference feature point, it is determined whether it conforms to the gamma features of the feature points above and below the reference feature point: If the actual gamma feature matches the gamma feature of the feature point adjacent to the reference feature point, output the current corresponding well depth, well deviation and actual feature point; If the actual gamma feature does not conform to the gamma features of the feature points adjacent to the reference feature point, determine whether it conforms to the gamma features of the remaining feature points respectively, and output the well depth, well deviation and all feature points that conform to the actual gamma feature at this time as a reference for manual judgment, and determine the actual feature point at the current positioning point through manual judgment; A5. After completing the positioning of the midpoint of the current footage, obtain the top surface distance of the positioning point based on the actual feature point obtained at the positioning point, and use the actual feature point as the new reference feature point for positioning the midpoint of the next footage; A6. Each drilling length is After the footage of L is achieved, steps A3-A5 are repeated, with the midpoint of the current footage being used as the positioning point. The gamma characteristics of the reference feature points determined in the previous segment are compared and judged, and the reference feature points are updated to achieve continuous positioning of the drill bit during the actual drilling process.

[0006] In some preferred embodiments, the actual gamma feature at the positioning point is obtained by: The current segment footage length L is divided into three equal parts along the footage direction to obtain three sub-intervals of equal length. The length of each sub-interval is L / 3; The medians of the natural gamma data, upper gamma data and lower gamma data of the middle subinterval are used as gamma representative values ​​of the natural gamma data, upper gamma data and lower gamma data at the positioning point, that is, actual gamma features.

[0007] In some preferred embodiments, the formation dip is calculated and updated by: Obtain the vertical depth of the positioning point and the well inclination angle of the starting point of this section of footage. Project the positioning point of this section of footage and the positioning point of the previous section of footage on the upper and lower interfaces of the box. Combined with the length of the current footage, the top surface distance of the positioning point, and the updated formation dip of the previous section of footage, analyze the geometric relationship and solve for the corresponding formation dip.

[0008] In some preferred embodiments, the well inclination angle of the lower footage is adjusted to perform geosteering, and the method is as follows: According to the natural gamma ray logging curve, the center area of ​​the box is selected as the optimal target area, and the center area is determined according to the center point of the box; Determine the distance between the characteristic point where the positioning point is located and the preset optimal target area, and adjust the well inclination angle according to the distance and angle difference to control the horizontal well drilling direction to ensure that the horizontal well is drilled to the optimal target area; The adjustment range of the well inclination angle does not exceed a preset adjustment threshold.

[0009] A second aspect of the present invention provides a horizontal drilling downhole geosteering automation system based on gamma-ray data while drilling, the system comprising: a data acquisition module configured to acquire natural gamma data and azimuthal gamma data of measurement while drilling in real time, wherein the azimuthal gamma data includes upper gamma data and lower gamma data; a positioning module configured to compare the natural gamma and azimuthal gamma data with gamma formation characteristics to determine the relative position of the drill bit and the casing at a current moment, wherein the gamma formation characteristics are obtained by extracting features from the natural gamma logging curve; a formation dip calculation module configured to obtain the well inclination angle and the vertical depth of the drill bit at a current moment, and calculate and update the formation dip in combination with the relative positions; The steering module is configured to determine the angle difference based on the well inclination angle and the formation dip angle at the current moment, and adjust the well inclination angle of the lower segment footage according to the relative position and the angle difference to perform geological steering.

[0010] Beneficial effects of the present invention: The present invention uses commonly used natural gamma and azimuthal gamma logging while drilling (LWD) methods to build automated decision-making logic, reducing subjective errors in manual analysis. At the same time, through mechanisms such as dynamic updating of benchmark feature points and real-time comparison of gamma features, drilling adjustments are more closely aligned with actual formation changes, improving response timeliness. Besides measuring wellbore trajectory engineering parameters (well depth, vertical depth, well inclination, etc.) while drilling, no other LWD equipment is required, meaning no additional economic costs are incurred. On-site monitoring and manual intervention when necessary are retained to avoid misjudgments, allowing for timely adjustment of the drilling direction under critical conditions, ultimately achieving a high box encounter rate, trajectory smoothness, and coordinated optimization of drilling efficiency. Through the two main steps of "positioning" and "decision-making," the system replicates the routine decisions made by geosteering engineers on-site during horizontal drilling and automatically transfers these decisions to the underground well. This significantly shortens the time interval from obtaining formation information to drilling adjustments, effectively resolving the response lag caused by data transmission and manual analysis in traditional manual decision-making models. This allows for faster underground response and enables instant adjustments under critical conditions, such as when the drill bit approaches the box boundary or when the well inclination deviates significantly from the formation dip. This optimizes decision-making accuracy, significantly reduces the risk of drilling out of the box, and ensures trajectory compatibility with the project. The automated decision-making process simultaneously considers the dogleg degree limitation of the rotary steerable drill bit and the need for subsequent fracturing. By smoothly adjusting the drilling direction to avoid large-angle bends, the engineering applicability of the wellbore trajectory is ensured, laying a good foundation for subsequent construction. It can achieve rapid drilling completion, reducing time costs and equipment wear. At the same time, the increased reservoir encounter rate can indirectly increase oil and gas production, comprehensively improving the economic benefits of unconventional oil and gas horizontal drilling. BRIEF DESCRIPTION OF THE DRAWINGS

[0011] Other features, objects and advantages of the present application will become more apparent upon reading the detailed description of non-limiting embodiments made with reference to the following drawings: Figure 1 is a flow chart of a horizontal drilling downhole geosteering automation method based on gamma-ray data while drilling in an embodiment of the present invention; Figure 2 is a vertical natural gamma change curve of the formation in the box and above and below the box obtained based on the well logging curve in the embodiment of the present invention; Figure 3 In the embodiment of the present invention, Figure 2 Analysis diagram of gamma features of different feature points; Figure 4 is a trajectory diagram of positioning the drill bit during the actual drilling process in an embodiment of the present invention; Figure 5 Schematic diagram of updating formation dip and calculating positioning point coordinates during drilling process according to an embodiment of the present invention; Figure 6 Schematic diagram of calculating trajectory starting point coordinates during drilling in an embodiment of the present invention. DETAILED DESCRIPTION

[0012] The present application will be further described in detail below with reference to the accompanying drawings and examples. It should be understood that the specific embodiments described herein are intended only to illustrate the relevant invention and are not intended to limit the invention. It should also be noted that, for ease of description, only portions relevant to the relevant invention are shown in the accompanying drawings.

[0013] It should be noted that, in the absence of conflict, the embodiments and features of the embodiments in this application can be combined with each other. The present application will be described in detail below with reference to the accompanying drawings and in combination with the embodiments.

[0014] The present invention obtains gamma formation characteristics based on logging curves, acquires natural gamma data and azimuthal gamma data measured while drilling in real time, determines the position by dynamically updating the benchmark feature points and comparing the gamma characteristics in real time, and then calculates the formation inclination and angular difference, performs geological guidance on drilling, and ultimately achieves a high box encounter rate, coordinated optimization of trajectory smoothness and drilling efficiency.

[0015] The invention provides a horizontal drilling downhole geosteering automation method based on gamma-ray data while drilling, comprising the following steps: Real-time acquisition of natural gamma data and azimuthal gamma data of measurement while drilling, wherein the azimuthal gamma data includes upper gamma data and lower gamma data; Comparing the natural gamma and azimuthal gamma data with gamma formation characteristics to determine the relative position of the drill bit and the casing at the current moment, wherein the gamma formation characteristics are obtained by extracting features from the natural gamma logging curve; Obtaining the well 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 positions; The angle difference is determined based on the well inclination angle and formation dip angle at the current moment, and the well inclination angle of the lower segment footage is adjusted according to the relative position of the drill bit and the angle difference to perform geosteering.

[0016] In order to more clearly illustrate the horizontal drilling downhole geosteering automation method based on the gamma ray data while drilling of the present invention, the following is combined with Figure 1 Each step in the embodiment of the present invention is described in detail.

[0017] The automated downhole geosteering method for horizontal drilling based on gamma-ray data while drilling according to the first embodiment of the present invention includes the following steps S1 to S4, each of which is described in detail as follows: S1. Acquire natural gamma data and azimuthal gamma data of measurement while drilling in real time, wherein the azimuthal gamma data includes upper gamma data and lower gamma data.

[0018] Preferably, before data acquisition, the vertical natural gamma ray variation curves of the formations in the box and above and below the box are obtained by fitting the natural gamma ray logging curve.

[0019] S2. Compare the natural gamma and azimuthal gamma data with gamma formation characteristics to determine the relative position of the drill bit and the casing at the current moment. The gamma formation characteristics are obtained by extracting features from the natural gamma logging curve.

[0020] Preferably, the gamma formation characteristics are obtained by extracting the characteristics of the natural gamma logging curve, and the method is as follows: Obtain the vertical natural gamma ray logging curve of the formation in the box where the target horizontal well is located and in the upper and lower parts of the box; Taking the midpoint of each section and each inflection point of the natural gamma logging curve as a feature point, and extracting the variation range of the natural gamma value of each feature point as the natural gamma feature at the feature point; Extract the gamma value within the preset range above each feature point as the upper gamma data of the feature point, and the gamma value within the preset range below the feature point as the lower gamma data of the feature point. The relative size relationship between the upper and lower gamma values ​​is used as the azimuth gamma feature of the feature point. Extract the distance from each feature point to the upper interface of the box as the top surface distance at the feature point; A gamma formation feature is constructed based on the natural gamma ray feature, the azimuthal gamma ray feature, and the top surface distance. The gamma formation feature includes corresponding data and correlation relationships of the natural gamma ray feature, the azimuthal gamma ray feature, and the top surface distance.

[0021] Further preferably, the feature point at the midpoint of each segment represents the segment, and the feature point at the inflection point only represents the point; when the natural gamma and orientation gamma features of adjacent feature points are the same, they are merged into one feature point.

[0022] Further preferably, the variation range of the natural gamma value of each feature point is the variation range of the gamma value within a preset range above and below each feature point. In this embodiment, the maximum and minimum natural gamma values ​​within the preset range are taken as the natural gamma features at the feature point.

[0023] Further preferably, the average value of the natural gamma values ​​within the preset range above each feature point is extracted as the upper gamma value of the feature point, and the average value of the natural gamma values ​​within the preset range below each feature point is extracted as the lower gamma value of the feature point.

[0024] During the actual drilling process, due to the unevenness of the formation, vibration during drilling, errors in the instrument itself, etc., even if the relative position of the drill bit and the box remains unchanged, the measured gamma data will still fluctuate within a certain range. Therefore, the drill bit position cannot be determined based on the gamma data of a single measurement, but needs to be determined based on a certain footage (length). L) data to make a comprehensive judgment.

[0025] Preferably, the natural gamma and azimuthal gamma data are compared with the gamma formation characteristics to determine the relative position of the drill bit and the casing at the current moment, and the method is as follows: A1. Set the starting point of the actual drilling process, obtain the formation inclination and well depth corresponding to the starting point based on the actual drilling fitting, compare them with the gamma formation characteristics, and determine the characteristic point corresponding to the starting point; A2. Determine the feature point corresponding to the starting point as the reference feature point of the first segment of footage, wherein the reference feature point includes a corresponding gamma feature; A3. Control the drill bit to drill a length of The footage of L, determine the midpoint of this footage as the positioning point; A4. Compare the actual gamma feature obtained at the 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, output the current corresponding well depth, well deviation and actual feature point; If the actual gamma feature does not conform to the gamma feature of the reference feature point, it is determined whether it conforms to the gamma features of the feature points above and below the reference feature point: If the actual gamma feature matches the gamma feature of the feature point adjacent to the reference feature point, output the current corresponding well depth, well deviation and actual feature point; If the actual gamma feature does not conform to the gamma features of the feature points adjacent to the reference feature point, determine whether it conforms to the gamma features of the remaining feature points respectively, and output the well depth, well deviation and all feature points that conform to the actual gamma feature at this time as a reference for manual judgment, and determine the actual feature point at the current positioning point through manual judgment; A5. After completing the positioning of the midpoint of the current footage, obtain the top surface distance of the positioning point based on the actual feature point obtained at the positioning point, and use the actual feature point as the new reference feature point for positioning the midpoint of the next footage; A6. Each drilling length is After the footage of L is achieved, steps A3-A5 are repeated, with the midpoint of the current footage being used as the positioning point. The gamma characteristics of the reference feature points determined in the previous segment are compared and judged, and the reference feature points are updated to achieve continuous positioning of the drill bit during the actual drilling process.

[0026] Further preferably, the gamma feature of the reference feature point includes a natural gamma feature and an orientation gamma feature of the reference feature point.

[0027] Further preferably, the actual gamma feature at the positioning point is obtained by: The current segment footage length L is divided into three equal parts along the footage direction to obtain three sub-intervals of equal length. The length of each sub-interval is L / 3; The medians of the natural gamma data, upper gamma data and lower gamma data of the middle subinterval are respectively used as gamma representative values ​​of the natural gamma data, upper gamma data and lower gamma data at the positioning point, that is, actual gamma features.

[0028] During horizontal drilling, it's often only necessary to adjust the drill bit's drilling angle (or inclination) vertically, without adjusting the drill bit's azimuth horizontally. Therefore, it's sufficient to calculate the change in formation inclination within the vertical plane of the drilling trajectory. After each drilling depth (∆L), the "positioning" process described above is performed to obtain the characteristic point ID of the current positioning point.

[0029] S3. Obtain the well inclination angle and vertical depth of the drill bit at the current moment, and calculate and update the formation dip angle based on the relative position, using the following method: Obtain the vertical depth of the positioning point and the well inclination angle of the starting point of this section of footage. Project the positioning point of this section of footage and the positioning point of the previous section of footage on the upper and lower interfaces of the box. Combined with the length of the current footage, the top surface distance of the positioning point, and the updated formation dip of the previous section of footage, analyze the geometric relationship and solve for the corresponding formation dip.

[0030] S4. Determine the angle difference based on the well inclination angle and the formation dip angle at the starting point of the current footage, and adjust the well inclination angle of the next footage according to the relative position and the angle difference to perform geosteering.

[0031] Preferably, the method of adjusting the well inclination angle of the lower footage to perform geosteering is as follows: According to the natural gamma ray logging curve, the center area of ​​the box is selected as the optimal target area, and the center area is determined according to the center point of the box; Determine the distance between the characteristic point where the positioning point is located and the preset optimal target area, and adjust the well inclination angle according to the distance and angle difference to control the horizontal well drilling direction to ensure that the horizontal well is drilled to the optimal target area; The adjustment range of the well inclination angle does not exceed a preset adjustment threshold.

[0032] Preferably, the central area is determined according to the center point of the box. In this embodiment, several feature point areas closest to the center point in the neighborhood of the center point are selected as the central area, and the feature point areas are preset range areas above and below the feature point.

[0033] Further preferably, three feature point regions closest to the center point within the neighborhood of the center point are selected as the center region.

[0034] Preferably, after obtaining the formation dip angle, 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 in combination with the vertical thickness of the box. The method is: Taking the projection point of the starting point on the upper interface of the box as the coordinate origin, the geometric relationship is analyzed according to the coordinates of the positioning point of the previous section of footage, and the coordinates of the positioning point of this section of footage and its projection on the upper and lower interfaces of the box are obtained.

[0035] During the actual drilling process, the real-time coordinates of the drill bit and the projection points on the upper and lower interfaces of the box, the positioning point well depth, well inclination and the corresponding feature points, formation dip and decision information made based on gamma feature comparison are transmitted to the uphole monitoring terminal. The uphole monitoring terminal is used for manual real-time monitoring. When an abnormal situation is detected, instructions can be issued through the uphole terminal for manual intervention, including pausing drilling, adjusting the footage length or recalibrating the benchmark feature points.

[0036] Further preferably, the abnormal conditions include: the actual gamma characteristics at the positioning point do not match the gamma characteristics of the reference characteristic point and its two adjacent characteristic points; the real-time coordinates transmitted to the well show that the drill bit deviates from the box by ≥0.5 meters; and the formation dip angle changes suddenly by ≥3°.

[0037] Preferably, in this embodiment, the horizontal drilling downhole geosteering automation method based on the gamma-ray data while drilling is used to control the horizontal drilling to be excavated at a certain location, and the method is: First, obtain the natural gamma ray log curve, such as Figure 2 As shown, feature extraction is performed to obtain gamma formation features. The specific steps are as follows: 1) Take the midpoint of each segment and each inflection point of the gamma curve as the feature point, extract the range of natural gamma value, and use it as the natural gamma feature at that point. Among them, the feature point at the midpoint of each segment represents the segment. For example, at feature point 7, the natural gamma value range is gr 7 L - gr 7 H ; The feature point at the inflection point only represents that point, such as the natural gamma value of feature point 8 is gr 8 .

[0038] 2) In addition to the natural gamma features, the azimuth gamma features at each feature point also need to be extracted, such as Figure 3 As shown in the figure, at feature point 10, upper gamma = 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 is not extracted as a feature point. This is 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 also the same as those of feature point 7, so no feature point is set again here.

[0039] 3) Take the distance from each feature point to the upper interface of the box d , such as 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 is negative; when the feature point is below the upper interface of the box,d Is positive.

[0040] The gamma stratigraphic characteristics of each characteristic point are shown in Table 1.

[0041] Table 1 Gamma stratigraphic characteristics of characteristic points

[0042] Second, obtain the natural gamma data and azimuthal gamma data of the drilling measurement in real time to determine the relative position of the drill bit and the box. The specific steps are as follows: 1) After the drill bit enters the box, set a starting point D 0 , the formation dip here α 0 It has been obtained by actual drilling fitting, and the well depth is L , and based on the natural gamma data and azimuth gamma data, it is clearly determined that the starting point is located at the feature point n At this feature point n It is the benchmark feature point of the next section of footage.

[0043] 2) Drilling a certain distance L Then, the midpoint of the footage is used as the positioning point D 1 , to determine whether the gamma feature at the positioning point still meets the reference feature point n Features: If it meets the requirements, then output the well depth at that time ( L +1 / 2 L ), well deviation θ , and feature point number n ; If it does not meet the requirements, then judge a feature point upwards and downwards respectively, that is, judge whether the current gamma feature meets the feature point ( n-1 ) and feature points ( n+1 ) features: If it meets the requirements, the well depth, well inclination and characteristic points at that time will be output; If it still does not meet the requirements, all remaining feature points are judged separately, and the well depth, well inclination and all matching feature point numbers are output as a reference for manual judgment.

[0044] After testing, the positioning point D 1 Comply with the benchmark feature points n , so far, the first section of footage after the starting point L The trajectory "positioning" at the midpoint has been completed, and the well depth here is ( L+1 / 2 L), the well inclination is θ , the drill bit is located at the feature point determined in the above steps.

[0045] 3) Get the positioning point D 1 After the feature point number is obtained, the positioning point is obtained D 1 Distance from the upper interface of the box d .

[0046] 4) Positioning point at this time D 1 The corresponding feature point becomes the new reference feature point for the "positioning" of the midpoint of the next segment footage; continue drilling, each segment L Such judgment is carried out after each drilling, so that the drill bit can be positioned during the actual drilling process (such as the attached Figure 4 ).

[0047] Third, according to the current positioning point D 2 and a certain point D 1 The characteristic point number can be used to update the formation dip between the two points. The specific steps are as follows: As attached Figure 5 , at the current positioning point D 2 and a certain point D 1 Draw a vertical line at the intersection of the upper interface of the box. S 1 、 S 2 Point, the intersection with the lower interface of the box is S′ 1 、 S′ 2 Point, analyzing the geometric relationship we can get: ; ; ; ; ; in, d 1 、 d 2 They are obtained during the positioning process D 1 、 D 2 The distance between the point and the top of the box; α 1For a certain point D 1 The corresponding formation dip angle, α 2 for S 1 and S 2 The dip angle of the formation between the points (unknown at this time and needs to be calculated); β This is the starting point of this section, i.e. the trajectory D 1 D 2 The well inclination angle at the midpoint can be obtained by MWD or LWD and is 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 Can be obtained based on MWD or LWD; In the above formula, only the formation dip α 2 is the unknown quantity, and we can solve the equation to get α 2 , which is S 1 and S 2 The dip angle between the strata.

[0048] Fourth, the upper fixed point is known D 1 The coordinates of ( 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 ), according to the previous fixed point D 1 The coordinates of ( x D1 ,y D1 ), calculate the current positioning pointD 2 The coordinates of ( x D2 ,y D2 ), analyzing the geometric relationship, we can get: ; ; The corresponding upper interface of the box S 2 Point coordinates( x S2 ,y S2 )for: ; ; Due to the thickness of the box d box It is often believed that it does not change, so the point D 2 Projection on the lower interface of the box S′ 2 The coordinates of the point are: ; ; From this, we can know that according to the coordinates of the previous fixed point, the current positioning point and the corresponding upper and lower interface coordinates of the box can be calculated.

[0049] Fifth, based on the drill bit positioning results and the difference between the formation dip and the well inclination (angle difference), adjust the well inclination for the next drilling. The specific steps are as follows: According to the actual situation of the project, select the appropriate feature point area in the box as the optimal area. If the drill head is far away from the optimal area, adjust the angle by a large amount; if the distance is close, adjust the angle by a small amount; if it is in the optimal area, make fine adjustments or no adjustments based on the angle difference.

[0050] Preferably, in this embodiment, select Figure 1 The characteristic point areas 8, 9, 10, and 11 in the middle of the middle box are taken as the optimal areas; the well inclination angle of the current positioning point is θ , angular difference γ = formation dip α -Well inclination angle θ. If the current positioning point is far from the optimal area (located at the 1-5 or 14-15 feature points), the well inclination angle is adjusted to the basis of the layer drilling (θ+γ), and then adjusted back by 2°. That is, if it is located at the 1-5 feature point, the well inclination angle needs to be reduced to make the drill bit closer to the optimal area. At this time, the well inclination angle is adjusted to ( θ+ γ-2If it is located at the 14-15 feature point, the well inclination angle needs to be increased to make the drill bit approach the optimal area. At this time, the well inclination angle is adjusted to ( θ+γ+2 If the current positioning point is close to the optimal zone (at feature points 6-7 or 12-13), the well inclination is adjusted to the base of in-bedding drilling and then adjusted back by 1°. If the current positioning point is within the optimal zone (at feature points 8-11) and the angle difference is greater than 0.5°, the well inclination is adjusted to in-bedding drilling. If the angle difference is less than or equal to 0.5°, no adjustment is made. To avoid decision errors caused by misjudgment of the feature point at the current positioning point, if two consecutive positioning points are not within the optimal zone, a large or small angle adjustment is performed according to the aforementioned principles. If only one positioning point is not within the optimal zone, no adjustment is made to avoid adjustment errors caused by misjudgment. If both positioning points are within the optimal zone, adjustment is made based on the angle difference. The next drilling decision is shown in Table 2.

[0051] Table 2 Drilling decision

[0052] Preferably, as long as the coordinates of the starting point are known, the coordinates of subsequent positioning points can be calculated. D 0 Projection point on the top of the box S 0 As the coordinate origin, D 0 The coordinates of a point are calculated as follows: Setting the starting point of the track D 0 When the formation dip α 0 It has been obtained through actual drilling fitting, and the characteristic point number representing its position has also been determined, so its distance from the upper interface of the box d 0 Also known; According to MWD or LWD, we can get D 0 The vertical depth TVD0 of the point. D 0 The coordinates are: ; ; After obtaining the coordinates of each positioning point and its projection points on the upper and lower interfaces of the box, these coordinate information can be transmitted to the manual monitoring platform on the well, and the top and bottom interfaces of the box and the drilling trajectory can be gradually drawn as the drilling process progresses. If any abnormality is found, the program judgment will be terminated in time, the manually judged feature point number and the next step instruction will be entered into the program, and then the program will be started for the next step of judgment.

[0053] Preferably, since the trajectory may be adjusted with a certain degree of dogleg, the trajectory D 1 D 2 It is not necessarily a straight line, so in this embodiment, the well inclination angle at its midpoint is used to represent the well inclination angle of this section.

[0054] Preferably, during the "positioning" process, it is allowed to search for a feature point upward or downward based on the feature point of the previous positioning point to obtain the feature point number of the current positioning point. At this time, the program may misjudge and cause the positioning result of the current positioning point to deviate by one feature point (generally, it will not deviate by two 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 positioning point, and the manual intervention mechanism will be activated).

[0055] It is further preferred that, since the inclination capability of the rotary steering equipment is limited to certain extent, such as 5° / 30m, that is, the well inclination angle can be adjusted by a maximum of 5° during the process of drilling 30m forward, when making a decision, it is required that the difference between the adjusted well inclination angle and the current well inclination angle must not exceed the inclination capability of the instrument, and the drilling should be carried out for a certain distance (such as 30m) after the last instruction to adjust the well inclination angle is issued before this instruction is issued.

[0056] Although the various steps in the above embodiment are described in the above-mentioned order, those skilled in the art will understand that in order to achieve the effect of this embodiment, different steps do not have to be executed in such an order. They can be executed simultaneously (in parallel) or in a reverse order. These simple changes are within the scope of protection of the present invention.

[0057] A second embodiment of the present invention provides a horizontal drilling downhole geosteering automation system based on gamma-ray data while drilling, the system comprising: a data acquisition module configured to acquire natural gamma data and azimuthal gamma data of measurement while drilling in real time, wherein the azimuthal gamma data includes upper gamma data and lower gamma data; a positioning module configured to compare the natural gamma and azimuthal gamma data with gamma formation characteristics to determine the relative position of the drill bit and the casing at a current moment, wherein the gamma formation characteristics are obtained by extracting features from the natural gamma logging curve; a formation dip calculation module configured to obtain the well inclination angle and vertical depth of the drill bit at a current moment, calculate and update the formation dip in combination with the relative positions; and determine the two-dimensional coordinates of the drill bit in the vertical plane based on the formation dip and the current drilling length; The steering module is configured to determine the angle difference based on the well inclination angle and the formation dip angle at the current moment, and adjust the well inclination angle of the lower segment footage according to the relative position and the angle difference to perform geological steering.

[0058] It should be noted that the horizontal drilling downhole geosteering automation system based on gamma-ray data while drilling provided in the above embodiment is only illustrated by the division of the above functional modules. In actual 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 embodiment can be combined 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 modules or steps and are not to be regarded as improper limitations on the present invention.

[0059] Those skilled in the art will clearly understand that, for the convenience and brevity of description, the specific working process and related instructions of the system described above can refer to the corresponding process in the aforementioned method embodiment and will not be repeated here.

[0060] A third embodiment of the present invention provides a horizontal drilling downhole geosteering automation device based on gamma ray data while drilling, comprising: at least one processor; and a memory communicatively connected to at least one of the processors; wherein, The memory stores instructions that can be executed by the processor, and the instructions are used to be executed by the processor to implement the above-mentioned horizontal drilling downhole geosteering automation method based on while-drilling gamma data.

[0061] A fourth embodiment of the present invention provides a computer-readable storage medium storing computer instructions, wherein the computer instructions are used to be executed by a computer to implement the above-mentioned horizontal drilling downhole geosteering automation method based on while-drilling gamma data.

[0062] Those skilled in the art will clearly understand that, for the convenience and brevity of description, the specific working processes and related instructions of the electronic device and computer-readable storage medium described above can refer to the corresponding processes in the aforementioned method embodiments and will not be repeated here.

[0063] Those skilled in the art should be able to appreciate that the modules and method steps of each example described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, computer software, or a combination of the two, and the programs corresponding to the software modules and method steps can be placed in random access memory (RAM), internal 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. In order to clearly illustrate the interchangeability of electronic hardware and software, the above description has generally described the components and steps of each example according to their functions. Whether these functions are performed in electronic hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art may use different methods to implement the described functions for each specific application, but such implementation should not be considered to be beyond the scope of the present invention.

[0064] Computer program code for performing the operations of the present application may be written in one or more programming languages, or a combination thereof, including object-oriented programming languages ​​such as Java, Smalltalk, C++, and conventional procedural programming languages ​​such as "C" or similar programming languages. The program code may be executed entirely on the user's computer, partially on the user's computer, as a stand-alone 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 a remote computer, the remote computer may be connected to the user's computer through any type of network, including a local area network (LAN) or a wide area network (WAN), or may be connected to an external computer (e.g., through the Internet using an Internet service provider).

[0065] 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.

[0066] The terms "first", "second", etc. are used to distinguish similar objects, rather than to describe or indicate a particular order or sequence.

[0067] The term "comprise" or any other similar term is intended to cover non-exclusive inclusion such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed or inherent to such process, method, article, or apparatus.

[0068] Thus far, the technical solutions of the present invention have been described in conjunction with 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 may make equivalent changes or substitutions to the relevant technical features, and the technical solutions after such changes or substitutions will fall within the scope of protection of the present invention.

Claims

1. A horizontal drilling downhole geosteering automation method based on gamma-ray data while drilling, characterized in that: The following steps are involved: Real-time acquisition of natural gamma data and azimuthal gamma data of measurement while drilling, wherein the azimuthal gamma data includes upper gamma data and lower gamma data; Comparing the natural gamma ray data and the azimuthal gamma ray data with the gamma ray formation characteristics to determine the relative position of the drill bit and the casing at the current moment, wherein the gamma ray formation characteristics are obtained by extracting features from the natural gamma ray logging curve; Obtaining the well 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 positions; The angle difference is determined based on the well inclination angle and formation dip angle at the current moment, and the well inclination angle of the lower segment footage is adjusted according to the relative position of the drill bit and the angle difference to perform geosteering.

2. The horizontal drilling downhole geosteering automation method based on while-drilling gamma data according to claim 1, characterized in that: The gamma formation characteristics are obtained by extracting the features of the natural gamma logging curve. The method is as follows: Obtain the vertical natural gamma ray logging curve of the formation in the box where the target horizontal well is located and in the upper and lower parts of the box; Taking the midpoint of each section and each inflection point of the natural gamma logging curve as a feature point, and extracting the variation range of the natural gamma value of each feature point as the natural gamma feature at the feature point; Extract the gamma value within the preset range above each feature point as the upper gamma data of the feature point, and the gamma value within the preset range below the feature point as the lower gamma data of the feature point. The relative size relationship between the upper and lower gamma values ​​is used as the azimuth gamma feature of the feature point. Extract the distance from each feature point to the upper interface of the box as the top surface distance at the feature point; A gamma formation feature is constructed based on the natural gamma ray feature, the azimuthal gamma ray feature, and the top surface distance. The gamma formation feature includes corresponding data and correlation relationships of the natural gamma ray feature, the azimuthal gamma ray feature, and the top surface distance.

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

4. The method for automated downhole geosteering of horizontal drilling based on gamma ray data while drilling according to claim 2, characterized in that: The average value of the natural gamma values ​​within the preset range above each feature point is extracted as the upper gamma value of the feature point, and the average value of the natural gamma values ​​within the preset range below each feature point is extracted as the lower gamma value of the feature point.

5. The method for automated downhole geosteering of horizontal drilling based on gamma ray data while drilling according to claim 2, characterized in that: The natural gamma and azimuthal gamma data are compared with the gamma formation characteristics to determine the relative position of the drill bit and the casing during measurement while drilling. The method is as follows: A1. Set the starting point of the actual drilling process, obtain the formation inclination and well depth corresponding to the starting point based on the actual drilling fitting, compare them with the gamma formation characteristics, and determine the characteristic point corresponding to the starting point; A2. Determine the feature point corresponding to the starting point as the reference feature point of the first segment of footage, wherein the reference feature point includes a corresponding gamma feature; A3. Control the drill bit to drill a length of The footage of L, determine the midpoint of this footage as the positioning point; A4. Compare the actual gamma feature obtained at the 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, output the current corresponding well depth, well deviation and actual feature point; If the actual gamma feature does not conform to the gamma feature of the reference feature point, it is determined whether it conforms to the gamma features of the feature points above and below the reference feature point: If the actual gamma feature matches the gamma feature of the feature point adjacent to the reference feature point, output the current corresponding well depth, well deviation and actual feature point; If the actual gamma feature does not conform to the gamma features of the feature points adjacent to the reference feature point, determine whether it conforms to the gamma features of the remaining feature points respectively, and output the well depth, well deviation and all feature points that conform to the actual gamma feature at this time as a reference for manual judgment, and determine the actual feature point at the current positioning point through manual judgment; A5. After completing the positioning of the midpoint of the current footage, obtain the top surface distance of the positioning point based on the actual feature point obtained at the positioning point, and use the actual feature point as the new reference feature point for positioning the midpoint of the next footage; A6. Each drilling length is After the footage of L is achieved, steps A3-A5 are repeated, with the midpoint of the current footage being used as the positioning point. The gamma characteristics of the reference feature points determined in the previous segment are compared and judged, and the reference feature points are updated to achieve continuous positioning of the drill bit during the actual drilling process.

6. The method for automated downhole geosteering of horizontal drilling based on gamma-ray data while drilling according to claim 5, characterized in that: The gamma features of the reference feature points include natural gamma features and orientation gamma features of the reference feature points.

7. The method for automated downhole geosteering of horizontal drilling based on gamma ray data while drilling according to claim 5, characterized in that: The actual gamma feature at the positioning point is obtained as follows: The current segment footage length L is divided into three equal parts along the footage direction to obtain three sub-intervals of equal length. The length of each sub-interval is L / 3; The medians of the natural gamma data, upper gamma data and lower gamma data of the middle subinterval are used as gamma representative values ​​of the natural gamma data, upper gamma data and lower gamma data at the positioning point, that is, actual gamma features.

8. The method for automated downhole geosteering of horizontal drilling based on gamma ray data while drilling according to claim 5, characterized in that: Calculate and update the formation dip as follows: Obtain the vertical depth of the positioning point and the well inclination angle of the starting point of this section of footage. Project the positioning point of this section of footage and the positioning point of the previous section of footage on the upper and lower interfaces of the box. Combined with the length of the current footage, the top surface distance of the positioning point, and the updated formation dip of the previous section of footage, analyze the geometric relationship and solve for the corresponding formation dip.

9. The method for automated downhole geosteering of horizontal drilling based on gamma ray data while drilling according to claim 5, characterized in that: Adjust the well inclination angle of the lower footage and perform geosteering. The method is as follows: According to the natural gamma ray logging curve, the center area of ​​the box is selected as the optimal target area, and the center area is determined according to the center point of the box; Determine the distance between the characteristic point where the positioning point is located and the preset optimal target area, and adjust the well inclination angle according to the distance and angle difference to control the horizontal well drilling direction to ensure that the horizontal well is drilled to the optimal target area; The adjustment range of the well inclination angle does not exceed a preset adjustment threshold.

10. A horizontal drilling downhole geosteering automation system based on gamma-ray data while drilling, used to implement the horizontal drilling downhole geosteering automation method based on gamma-ray data while drilling according to any one of claims 1 to 9, characterized in that: The system comprises: a data acquisition module configured to acquire natural gamma data and azimuthal gamma data of measurement while drilling in real time, wherein the azimuthal gamma data includes upper gamma data and lower gamma data; a positioning module configured to compare the natural gamma and azimuthal gamma data with gamma formation characteristics to determine the relative position of the drill bit and the casing at a current moment, wherein the gamma formation characteristics are obtained by extracting features from the natural gamma logging curve; a formation dip calculation module configured to obtain the well inclination angle and the vertical depth of the drill bit at a current moment, and calculate and update the formation dip in combination with the relative positions; The steering module is configured to determine the angle difference based on the well inclination angle and the formation dip angle at the current moment, and adjust the well inclination angle of the lower segment footage according to the relative position and the angle difference to perform geological steering.

Images