Automatic geosteering based on distance to oil-water contact

Abstract

Examples described herein provide a computer-implemented method for performing automatic geosteering. The method includes receiving, by a processing system, formation evaluation data from a bottom hole assembly disposed in a wellbore. The method also includes determining, by the processing system, position data of a formation boundary from the formation evaluation data. The method also includes extrapolating, by the processing system, the position data to generate extrapolated position data of the formation boundary. The method also includes adjusting a trajectory of the wellbore based at least in part on the extrapolated position data of the formation boundary.

Description

[0001] Cross-references to related applications

[0002] This application claims the benefit of U.S. Application Serial No. 62 / 989,020, filed March 13, 2020, the entire disclosure of which is incorporated herein by reference. Background Technology

[0003] The implementation scheme described in this article relates generally to downhole exploration and mining operations in the resource extraction industry, and more specifically to technologies for automated geological guidance based on distances to formation boundaries.

[0004] Downhole exploration and production operations involve the deployment of a variety of sensors and tools. Sensors, for example, provide information about the downhole environment by collecting data on temperature, density, saturation, and resistivity, as well as many other parameters. This information can be used to control various aspects of drilling and tools or systems located in bottom-hole components, along the drill string, or on the surface. Summary of the Invention

[0005] Embodiments of the present invention relate to performing automatic geological guidance based on the distance to the oil-water interface.

[0006] A non-limiting example method for performing automated geological steering includes receiving formation assessment data from a bottomhole assembly disposed in a wellbore by a processing system. The method further includes determining location data of formation boundaries by the processing system based on the formation assessment data. The method also includes extrapolating the location data by the processing system to generate extrapolated location data of the formation boundaries. The method further includes adjusting the wellbore trajectory based at least in part on the extrapolated location data of the formation boundaries.

[0007] A non-limiting example system for automated geological steering of a wellbore includes a bottomhole assembly disposed within the wellbore and a processing system for executing computer-readable instructions that control the processing system to perform operations. The operations include receiving formation assessment data from the bottomhole assembly disposed within the wellbore by the processing system. The operations also include determining location data of formation boundaries by the processing system based on the formation assessment data. The operations further include extrapolating the location data by the processing system to generate extrapolated location data of the formation boundaries. The operations also include adjusting the trajectory of the wellbore based at least in part on the extrapolated location data of the formation boundaries.

[0008] Other embodiments of the present invention implement the features of the above-described method in computer systems and computer program products.

[0009] Additional technical features and benefits are achieved through the technology of this invention. Embodiments and aspects of the invention are described in detail herein and are considered part of the claimed subject matter. For a better understanding, refer to the detailed description and accompanying drawings. Attached Figure Description

[0010] Referring now to the accompanying drawings, in which similar elements in several drawings have similar numbers:

[0011] Figure 1 A cross-sectional view of a wellbore operating system according to one or more embodiments described herein is depicted;

[0012] Figure 2 The present invention describes one or more embodiments according to the present invention. Figure 1 A block diagram of the processing system that can be used to implement the technology herein;

[0013] Figure 3A A cross-sectional view of a wellbore operating system according to one or more embodiments described herein is depicted;

[0014] Figure 3B Another cross-sectional view of a wellbore operating system according to one or more embodiments described herein is depicted; and

[0015] Figure 4 A flowchart is depicted for a method for performing automated geological guidance according to one or more embodiments described herein. Detailed Implementation

[0016] A modern bottom-of-well assembly (BHA) consists of several distributed components such as sensors and tools, each of which performs data acquisition and / or processing for a specific purpose. An example of one type of data acquired may include electromagnetic data.

[0017] Drilling wells below the surface to extract hydrocarbons and for other purposes. Specifically, Figure 1 A cross-sectional view of a wellbore operating system 100 according to various aspects of this disclosure is depicted. In conventional wellbore operations, logging-while-drilling (LWD) measurements are performed during drilling operations to determine the formation rock and fluid properties of formation 4. Those properties are then used for various purposes, such as estimating reserves based on saturation logging, defining completion settings, etc., as described herein.

[0018] Figure 1 The system and arrangement shown are an example illustrating a downhole environment. While this system can operate in any subsurface environment, Figure 1 The diagram shows a support 5 installed in a borehole 2 that penetrates the formation 4. The support 5 is installed in the borehole 2, located at the distal end of the borehole 2, as shown... Figure 1 As shown.

[0019] like Figure 1 As shown, the support 5 is a drill string including a bottom-hole assembly (BHA) 13. The BHA 13 is part of the operating system 100 and includes drill collars, stabilizers, reamers, etc., and drill bit 7. In this example, drill bit 7 is positioned at the front end of the BHA 13. The BHA 13 also includes sensors (e.g., measuring tool 11) and electronics (e.g., downhole electronics 9). Measurements collected by the measuring tool 11 may include, for example, measurements related to drill string operations. The BHA 13 also includes a steering tool configured to guide the BHA 13 and drill bit 7 in a desired direction. The steering tool can receive steering instructions, based on which it generates steering forces to push or point drill bit 7 in the desired direction. The operating system 100 is configured to perform drilling operations, such as rotating the drill string, thereby rotating drill bit 7. The drilling rig 8 also pumps drilling fluid through the drill string 5 to lubricate drill bit 7 and flush cuttings from the borehole 2. According to one or more embodiments described herein, the measurement tool 11 and downhole electronics 9 are configured to perform one or more types of measurements in an embodiment referred to as logging while drilling (LWD) or measurement while drilling (MWD).

[0020] Raw data is collected by measuring tool 11 and transmitted to downhole electronics 9 for processing. This data can be transmitted between measuring tool 11 and downhole electronics 9 via cable 6 (such as wire (e.g., power line) or wireless link), which transmits power and / or data between the measuring tool 11 and downhole electronics 9. Power is generated downhole via a turbine generator assembly (not shown), and communication with the surface 3 (e.g., with processing system 12) is cableless (e.g., using mud pulse telemetry, electromagnetic telemetry, etc.) and / or cable-bound (e.g., using a cable to processing system 12, such as via wired conduit). Data processed by downhole electronics 9 can then be telemetryally transmitted to the surface 3 for further processing or display by processing system 12.

[0021] According to embodiments of this disclosure, drilling control signals may be generated by processing system 12 (e.g., based on raw data collected by measuring tool 11) and transmitted downhole, or may be generated within downhole electronics 9 or by a combination of both. Downhole electronics 9 and processing system 12 may each include one or more processors and one or more memory devices. In alternative embodiments, computing resources such as downhole electronics 9, sensors, and other tools may be positioned along support 5, rather than, for example, within BHA 13. The borehole 2 may be vertical as shown, or may be in other orientations / arrangements (see, for example...). Figure 3A , Figure 3B ).

[0022] It should be understood that the embodiments of this disclosure can be implemented in conjunction with any other suitable type of computing environment now known or developed in the future. For example, Figure 2 Depicting Figure 1 A block diagram of a processing system 12 is provided, which can be used to implement the techniques described herein. In the example, the processing system 12 has one or more central processing units 21a, 21b, 21c, etc. (collectively or collectively referred to as processor 21 and / or processing device 21). In aspects of this disclosure, each processor 21 may include a Reduced Instruction Set Computer (RISC) microprocessor. The processor 21 is coupled to system memory (e.g., random access memory (RAM) 24) and various other components via a system bus 33. Read-only memory (ROM) 22 is coupled to the system bus 33 and may include a Basic Input / Output System (BIOS) that controls certain basic functions of the processing system 12.

[0023] Input / output (I / O) adapter 27 and network adapter 26 coupled to system bus 33 are also shown. I / O adapter 27 may be a Small Computer System Interface (SCSI) adapter for communicating with memory such as hard disk 23 and / or tape storage drive 25 or any other similar component. I / O adapter 27 and memory (such as hard disk 23 and tape storage device 25) are collectively referred to herein as mass storage device 34. Operating system 40 for execution on processing system 12 may be stored in mass storage device 34. Network adapter 26 interconnects system bus 33 with external network 36, enabling processing system 12 to communicate with other systems.

[0024] A display (e.g., a display monitor) 35 is connected to the system bus 33 via a display adapter 32, which may include a graphics adapter and a video controller for improving the performance of graphics-intensive applications. In one aspect of this disclosure, adapters 26, 27, and / or 32 may be connected to one or more I / O buses, which are connected to the system bus 33 via an intermediate bus bridge (not shown). Suitable I / O buses for connecting peripheral devices such as hard disk controllers, network adapters, and graphics adapters typically include common protocols such as Peripheral Component Interconnect (PCI). Additional input / output devices are shown connected to the system bus 33 via a user interface adapter 28 and a display adapter 32. A keyboard 29, a mouse 30, and a speaker 31 may be interconnected to the system bus 33 via a user interface adapter 28, which may include, for example, a super I / O chip integrating multiple device adapters into a single integrated circuit.

[0025] In some aspects of this disclosure, the processing system 12 includes a graphics processing unit 37. The graphics processing unit 37 is a specialized electronic circuit designed to manipulate and modify memory to accelerate the creation of images in a frame buffer intended for output to a display. Generally, the graphics processing unit 37 is highly efficient in manipulating computer graphics and image processing, and has a highly parallel architecture, making it more efficient than a general-purpose CPU for algorithms that perform parallel processing of large data blocks.

[0026] Therefore, as configured herein, the processing system 12 includes processing power in the form of a processor 21, storage capacity including system memory (e.g., RAM 24 and mass storage device 34), input components (such as a keyboard 29 and a mouse 30), and output capacity including a speaker 31 and a display 35. In some aspects of this disclosure, a portion of the system memory (e.g., RAM 24 and mass storage device 34) collectively stores an operating system to coordinate the functions of the various components shown in the processing system 12.

[0027] Based on the examples described herein, techniques for automated geological steering are provided. During geological steering, it may be desirable to maintain a certain distance between the BHA and different stratigraphic features, such as stratigraphic boundaries within stratigraphy 4, for example, the boundary between two different strata (e.g., sandstone and shale), an oil-water contact surface, or a fluid-gas contact surface. The boundary between two different strata (e.g., sandstone and shale) is the surface in which two strata in stratigraphy 4 come into contact. Similarly, an oil-water contact surface or a fluid-gas contact surface is a surface in stratigraphy 4 where oil and water, or fluid and gas, come into contact within the stratum, or where oil saturation, water saturation, and / or gas saturation have different values ​​(such as predetermined values). Typically, an oil-water contact surface represents a surface where oil is on top and water is below, and a fluid-gas contact surface represents a surface where gas is on top and fluid is below. Stratigraphic features such as stratigraphic boundaries (e.g., the boundary between two different strata, an oil-water contact surface, or a fluid-gas contact surface) may vary spatially and may not be flat areas.

[0028] To achieve optimal hydrocarbon recovery from a hydrocarbon reservoir, it may be desirable to drill the wellbore at a desired distance from the formation boundary. Therefore, the techniques for automated geosteering described herein provide a method for guiding bottomhole components based on inversion of downhole measurements (data) to achieve and maintain a desired / optimal distance between at least a portion of the BHA (e.g., the drill bit) and the predicted formation boundary. The desired well trajectory can be continuously updated based on downhole measurements.

[0029] Specifically, this technique utilizes downhole measurement results (data) (e.g., formation assessment measurement results (data), such as electromagnetic, acoustic, or nuclear data / measurement results (data)) to quantify the actual distance between the BHA and the formation boundary. This data is then used to guide the BHA and associated drill bit to an optimal location relative to the formation boundary (e.g., for oil production). This is performed by determining the target dip angle to achieve the optimal true vertical depth (TVD) and dip angle placement of the BHA, based on a predicted inclination (based on previously measured data points), sharp turn severity, and optimal TVD placement determined using regression techniques.

[0030] Figure 3A A cross-sectional view of subsurface 300 according to one or more embodiments described herein is depicted. Subsurface 300 includes the actual path 306 of BHA 13 traveling through formation 4. It is expected that BHA 13 will be at a distance from the formation boundary (in this example, the formation boundary is the oil-water contact region 302). Figure 3A In a cross-sectional view, the oil-water contact area 302 is represented by an oil-water contact line, maintaining a desired distance 308, for example, to enhance hydrocarbon recovery. Therefore, it is desired that the BHA 13 travels along a desired well trajectory or expected path 304 at a desired distance 308 from the oil-water contact area 302. The distance from the BHA 13 to the oil-water contact area 302 can be determined, for example, using electromagnetic, acoustic, or nuclear data collected by the BHA 13 or by another suitable device.

[0031] like Figure 3A As shown, BHA 13 includes a measurement point 310 for collecting / measuring data. As an example, measurement point 310 coincides with the location of a measuring tool (e.g., one or more of the measuring tools 11, sensors on one or more of the measuring tools 11, or the location of a receiver and / or transmitter on one or more of the measuring tools 11 relative to receivers and transmitters included in one or more of the measuring tools 11). The measuring tool collects data (e.g., electromagnetic, acoustic, or nuclear data) at measurement point 310 regarding the location or distance of the oil-water contact area 302 (e.g., the location or distance of the oil-water contact area relative to the location of measurement point 310) at a point prior to the current location of the measuring tool. For example, the measuring tool 11 collects data at the measurement point 310 (i.e., the point or location in space where data is collected) to identify or determine the distances to location points 312a, 312b, 312c, 312d, and 312e, where location point 312a is the location or location of the oil-water contact area in space where the latest data (i.e., data from the most recently collected data point) is collected, and location point 312e is the location or location of the oil-water contact area in space where the oldest data is collected.

[0032] Location points 312a, 312b, 312c, 312d, and 312e include data based on which the distance from BHA 13 to the oil-water contact region 302 at each of the acquisition locations 312a-312e can be determined. A simple transformation can be used to determine the distance from BHA 13 to the oil-water contact region 302 at each of the acquisition locations 312a-312e. In another embodiment, an inversion can be performed to determine the distance from BHA 13 to the oil-water contact region 302 at each of the acquisition locations 312a-312e. In the inversion, the formation can be simulated in a computer model. The simulated formation can be characterized by two or more sub-regions, which can be characterized by parameters such as resistivity, conductivity, dielectric constant (for EM measurements) or impedance, density (for acoustic measurements) or oil saturation, water saturation, and lithology. Two or more sub-regions in the simulated formation can be used to create a formation boundary between them, characterized by parameters of the adjacent sub-regions and the location of the formation boundary (such as the distance to the measuring tool or another different point in the formation (e.g., the location of drill rig 8)). Finally, one or more hypothetical locations of the measuring tool during one or more measurements are simulated in a computer model. Using these assumptions, one or more simulated measurement results can be calculated using methods known in the art. The one or more simulated measurement results can then be compared with one or more actual measurements of BHA 13, and parameters can be varied, including the location of the formation boundary relative to one or more hypothetical locations of the measuring tool during one or more measurements, until the simulated and actual measurement results are sufficiently close (e.g., the difference or ratio between the simulated and actual measurement results is within a predetermined range or below a predetermined value). When the simulated and actual measurement results are sufficiently close, the parameters used to create the simulated measurement results are assumed to be determined.

[0033] As an example, the results of inverting the data are used to guide BHA 13, and this information is predicted in front of the drill bit to determine what guidance instructions are useful so that the actual path 306 of BHA 13 (i.e., the wellpath) is parallel to the oil-water contact area 302 and at a desired distance from it.

[0034] Predict the current well path ahead of the drill bit position using dip data and / or azimuth. As an example, load formation assessment data and acquire directional survey data, such as dip data and / or azimuth data. Survey data (e.g., near-bit dip log) can be filtered by applying filters (such as rate of change filters) to remove any out-of-bounds points. A rate of change filter can filter out out-of-bounds points from the near-bit dip log that fall outside a predetermined rate of change of the drill bit's inclination angle. Assuming an azimuth / dip angle (e.g., a calculated or modeled azimuth / dip angle or an azimuth / dip angle measured or acquired at one or more previous survey stations), and for one or more samples from the azimuth / dip angle (e.g., near-bit dip angle) or formation assessment data, the survey can be calculated based on the assumed azimuth / dip angle using formulas (such as the minimum curvature formula). The minimum curvature method assumes a relationship between the coordinate differences (such as the difference between horizontal coordinates (e.g., horizontal coordinates relative to east and north) and vertical coordinates (e.g., TVD)) of two points in space and the survey data (such as azimuth, dip, and depth) at those two points. For example, if the azimuth, dip, and depth at survey points I and II are A1, I1, MD1 and A2, I2, MD2, respectively, then the coordinate difference between survey points I and II can be calculated using the following formula.

[0035] N2–N1=(MD2–MD1) / 2x[sinI1 cosA1+sinI2 cosA2]x RF

[0036] E2–E1=(MD2–MD1) / 2x[sinI1 sinA1+sinI2 sinA2]x RF

[0037] TVD2–TVD1=[cosI1+cosI2]x RF

[0038] Where: RF=2tan(β / 2) / β

[0039] And β=acos(cos(I2–I1)–sinI1 x sinI2 x(1–cos(A2–A1).

[0040] N2, E2, TVD2 and N1, E1, TVD1 are the horizontal coordinates relative to north, the horizontal coordinates relative to east, and the TVD at measurement points II and I, respectively. These formulas allow the calculation of the coordinate difference between two points in space based on measurement data from two points in space, and vice versa.

[0041] In some cases, the average of two or more samples can be used as azimuth / dip / formation assessment data. This approach is more robust when data quality is poor. In the example, this approach is performed iteratively as BHA 13 advances along the actual path 306. Each iteration can begin from the previously performed survey, thus minimizing the assumed distance of the well azimuth.

[0042] In some cases, anomalies may occur when determining how to adjust the trajectory of BHA 13. Anomalies occur when unexpected events are encountered, such as when values ​​exceed acceptable ranges. When an anomaly occurs, an anomaly flag (i.e., an error flag) can be set. An example of an anomaly is when the rate of change of the slope of the formation boundary (i.e., the oil-water interface) (e.g., the angle of the formation boundary relative to the horizontal at a point) falls outside the expected range. For example, an anomaly occurs if the difference between the location, TVD, or actual path 306 calculated at a previous location (e.g., location point 312b) and the distance calculated at the current location (e.g., the current location of measurement point 310) divided by the distance between the previous and current locations (e.g., the difference in measurement depth) is greater than a threshold (e.g., a predetermined threshold). Similarly, an anomaly may occur if the difference between the slope of the formation boundary calculated at a previous location (e.g., location point 312b) and the slope of the formation boundary calculated at the current location (e.g., the current location of measurement point 310), divided by the distance between the previous and current locations (e.g., the difference in measurement depth), is greater than a threshold (e.g., a predetermined threshold). In such cases, the inversion result can be ignored. Another such anomaly occurs when the curve does not match the formation boundary (i.e., when the curve matching the formation boundary is outside an acceptable threshold (such as a predetermined threshold)). Another anomaly occurs when the gamma value (which can be measured by the measuring tool 11 of BHA13) is higher than a threshold (such as a predetermined threshold). In the event of an anomaly being detected, an error flag can be set. The error flag can serve as an indicator to the operator that an anomaly has occurred. Another such anomaly occurs when the penetration rate of BHA 13 decreases and the weight on the drill bit increases. In such cases, the well may be drilling into hard formations, such as calcite struts, which have low porosity and therefore little fluid, resulting in high measured resistivity. When one or more of these (or other) anomalies occur, the corresponding measurements, calculations, or inversions can be ignored. Another example of anomalies occurs when the predicted well path is shallower than the defined formation boundary. In this case, the predicted well path can be adjusted downwards to an acceptable / permissible minimum total vertical depth. Another example of anomalies occurs when the interval between the density curve and the neutron porosity curve is greater than a predetermined limit when plotted on a standard scale. In this case, the estimated TVD of the formation boundary contact can be adjusted to the TVD of the actual well path.

[0043] The predicted well path ahead of the drill bit includes prediction point 316, which is the target to which BHA 13 will be guided (e.g., a target point or setpoint used for manual, automatic, or semi-automatic control processes to guide BHA 13 (e.g., a controlled closed-loop system used to guide BHA 13)). In one or more examples, the average azimuth / dip / formation assessment data values ​​of the last "n" location points (e.g., location points 312a-312e) are calculated as described herein.

[0044] Using the predicted oil-water contact area 302, predicted points (i.e., target points or setpoints) 316 with a desired distance from the predicted oil-water contact area are determined. For this purpose, the nearest location point (e.g., location point 312a) is considered. However, in some examples, one or more of previous location points 312b-312d are also considered, for example, by working backward from the nearest location point in time. By determining one or more of location points 312a-312e, the location of the oil-water contact area 302 can be extrapolated using any known extrapolation technique (such as linear regression) to generate extrapolated location data. This extrapolation technique is capable of determining curve parameters of the predicted oil-water contact area, such as slope and offset.

[0045] The BHA is then guided, for example, by adjusting the trajectory of the BHA 13 toward the predicted point 316. In some examples, an intermediate point 314 is similarly determined, and multiple intermediate points may exist between the current position of the drill bit 7 and the predicted point 316. The path between any two of these points (e.g., between the drill bit 7 and intermediate point 314, between two intermediate points, and between intermediate point 314 and the predicted point 316) may have a different inclination angle than other areas of the path of the BHA 13. This allows the BHA 13 to be guided onto the intended path 304 without overshooting.

[0046] Now go to Figure 3B This shows the various aspects of the disclosed method in more detail. Similar to... Figure 3A , Figure 3BA cross-sectional view of a subsurface 300 according to one or more embodiments described herein is depicted. A borehole is drilled into the subsurface 300 by a BHA 13 including a drill bit 360 along an actual path (or actual well trajectory) 350. Along the actual path 350, the BHA 13 approaches a formation boundary 340, which may be at least partially a flat area or may be a curved surface. A setpoint 370a is defined in space to guide the BHA 13 along the intended path (or planned well trajectory) 350a. The BHA 13 includes measurement points 310 for collecting / measuring data. As an example, measurement points 310 coincide with the location of measuring tools in the BHA 13 (e.g., one or more measuring tools, sensors on one or more measuring tools, or the location of receivers and / or transmitters on one or more measuring tools relative to receivers and transmitters included in one or more measuring tools). The measuring tool collects data (e.g., electromagnetic, acoustic, or nuclear data) at measurement point 310 regarding points on the stratigraphic boundary prior to the current position of the measuring tool (e.g., location or distance data regarding the stratigraphic boundary relative to measurement point 310). For example, the measuring tool collects data at measurement point 310 at data points 331, 332, 333, and 334 (i.e., points or locations in space where data is collected), where data point 331 is the point or location in space where the most recent data was collected (i.e., the most recently collected data point), and data point 334 is the point or location in space where the oldest data was collected. In various respects, the measuring tool measures or collects data that can be used to determine the distances d from the corresponding data points 331, 332, 333, and 334 to the corresponding location points I, II, III, and IV. 331 d 332 d 333 and d 334 Data, such as Figure 3B As shown.

[0047] Data points 331, 332, 333, and 334 and their corresponding measurement times t 331 t 332 t 333 and t 334 (Not shown) These measurement times are associated with the time when data was collected at the data points. Similarly, data points 331, 332, 333, and 334 are associated with the corresponding measurement depths D at which the data was collected. 331 D 332 D 333 and D 334(Not shown) Associated (“measured depth” is the industry term for the distance from a reference point (such as the surface) along the actual well trajectory 350). Additionally, data points 331, 332, 333, and 334 may be associated with orientation data of BHA 13 (such as the azimuth or dip of BHA 13). For example, data point 331 may be associated with the azimuth and dip of BHA 13 at the location of data point 331, data point 332 may be associated with the azimuth and dip of BHA 13 at the location of data point 332, and so on. Orientation data of BHA 13 may be collected by orientation sensors (such as magnetometers, gravimeters, accelerometers, and / or gyroscopes) in BHA 13. The orientation data associated with data points 331, 332, 333, and 334 can be measured at the locations of data points 331, 332, 333, and 334, or can be derived from orientation data measured at locations different from data points 331, 332, 333, and 334 (e.g., obtained, interpolated, or extrapolated from orientation data measured at locations different from data points 331, 332, 333, and 334). This is based on the measurement depth D. 331 D 332 D 333 and D 334 And the associated orientation data, the coordinates of the corresponding data points 331, 332, 333 and 334 can be derived as is known in the art (e.g., three-dimensional coordinates relative to the origin (such as drill rig 8), or relative to the origin such as... Figure 3A , Figure 3B The coordinates / TVD of data points 331, 332, 333, and 334, and the distance d, are used to determine the two-dimensional coordinates of the cross-section shown and / or the true vertical depth (TVD). 331 -d 334 Data collected at data points 331, 332, 333, and 334 can be used to derive the coordinates / TVD of the location points I, II, III, and IV of the stratigraphic boundaries, as further disclosed herein.

[0048] Figure 3B Indicates distance d 331 -d 334 Individual data points I-IV are insufficient to construct the location of stratigraphic boundary 340 because there is uncertainty in the detected orientation relative to stratigraphic boundary 340 for each data point 331-334. This is represented by spheres K1-K4, where the corresponding data points 331-334 are the center point and the corresponding distance d. 331 -d 334 As the radius. For example, K1 has data point 331 as the center point and distance d. 331 As the radius, K2 has data point 332 as the center point and distance d. 332 As the radius, and so on. If only the distance d is known...332 Then, the location point II of formation boundary 340 can be anywhere on sphere K2. In other words, the distance from data point 332 to formation boundary 340 is measured along a line not perpendicular to the actual well trajectory 350. However, considering two or more data points when constructing location point II of formation boundary 340 can help significantly reduce uncertainty. For example, if d is known... 331 d 332 d 333 and d 334 Therefore, it can be concluded that the location of the stratigraphic boundary cannot be at any point on sphere K2, but can only fall on sphere segments K2' and K2'", which do not fall within one or more corresponding spheres of other data points (e.g., spheres K1, K3, and / or K4 of corresponding data points 331, 333, and / or 334). This helps determine where location point II of stratigraphic boundary 340 must be located. In other words, the point in space identified as the location point of stratigraphic boundary 340 based on the data points cannot be closer to any other data point than the corresponding distance from other data points to stratigraphic boundary 340. Therefore, stratigraphic boundary 340 is constructed from the data points in a manner that is a measured distance from the data points and at the same time not less than a measured distance from another data point.

[0049] Alternatively or otherwise, other information or criteria may be used to construct the stratigraphic boundary 340 based on one or more data points 331…334. For example, the stratigraphic boundary 340 may be constructed by applying a minimum curvature criterion to the constructed stratigraphic boundary 340. For example, only those points outside of spherical segments K2' and K2” may be selected to construct the stratigraphic boundary 340 such that the curvature of the constructed stratigraphic boundary 340 is minimized. Additionally, the data collected at data points 331…334 may include directional data indicating the direction in which the stratigraphic boundary 340 is located relative to BHA 13 (e.g., the tool face direction). An example of such data including directional data is an image (e.g., an image around the measuring tool or an image parallel to the measuring tool). For example, if location point II is located at spherical segment K2' or K2”, the directional data may be used to determine whether either of these spherical segments can be eliminated (e.g., by indicating that the stratigraphic boundary is located below BHA 13” rather than above BHA 13”).

[0050] In one implementation, it can be achieved through communication with about Figure 3A The inversion described is similar to the inversion used to determine location data (such as distance d). 331 d 332 d 333 and d 334(and / or the coordinates / position / TVD of location points I-IV). Inversion can be performed individually for each data point 331…334 (single-point inversion). Alternatively, the inversion may include more than one data point to determine the coordinates / position / TVD of the location point and / or the distance to the location point for each data point (multi-point inversion). For example, to determine the coordinates / position / TVD of location point II or the distance d between data point 332 and location point II. 332 Data measured at data point 332, as well as data measured at data points 333 and / or 331, can be used for inversion. Generally, multi-point inversion results in higher confidence levels as more input data is used. Inversion may also include various data measured at a single data point. For example, BHA 13 may include one or more measuring instruments for electromagnetic measurements utilizing various operating frequencies and / or various transmitter-receiver spacings. Similarly, BHA 13 may include one or more measuring instruments for acoustic measurements utilizing at least one of various operating frequencies, various transmitter-receiver spacings, and various excitation modes. Furthermore, BHA 13 may include measuring instruments for more than one physical characteristic. For example, BHA 13 may include measuring instruments for electromagnetic measurements and measuring instruments for acoustic measurements. Various combinations of different physical characteristics, operating frequencies, transmitter-receiver spacings, and / or excitation modes can be used as input data for inversion (single-point inversion or multi-point inversion).

[0051] As discussed herein, the spatial coordinates / position / TVD of location point I-IV or the distance to location point I-IV can be derived from the measurement results at data points 331…334. The coordinates / position / TVD of location point I-IV or the distance to location point I-IV can then be extrapolated, for example, in a certain direction (such as in a direction parallel to the planned well trajectory 350a), to create an extrapolated formation boundary 340. A predetermined number of location points can be used to create the extrapolated formation boundary 340. For example, 5, 10, or 20 location points, or all location points whose coordinates / position / TVD or distance are determined within a certain time interval (such as the last 20 seconds, the last 60 seconds, or the last 180 seconds), can be used to create the extrapolated formation boundary 340. Extrapolation methods for 2D curves or 3D surfaces, such as fitting, can be applied. For example, a fitting (such as a polynomial fitting or regression) can be applied to location point I-IV, which produces analytical equations or formulas (e.g., polynomials) or algorithms (e.g., computer algorithms) that allow for the calculation of the coordinates / location / TVD of location point I-IV or the distance to location point I-IV in an accurate or approximate manner. The parameters of the equations or formulas (such as constants in a polynomial) are then the result of the fitting, which can be used to calculate the location data of formation boundary 340 at coordinates / location / TVD different from those of location point I-IV. Alternatively or additionally, the fitting can be used to determine the distance from any point (e.g., the planned well trajectory 350a or a point on the drill bit) to formation boundary 340 (e.g., the distance d from set point 370a). 370a The distance from a point 350a from the planned well trajectory can be compared with the desired distance d. 370b(Such as a predetermined distance threshold) can be compared. Therefore, well trajectory 350a can be adjusted to an adjusted well trajectory (e.g., by adjusting setpoint 370a to an adjusted setpoint 370b) to ensure that the distance from one or more points on the adjusted well trajectory 350b to the formation boundary 340 is within a desired range, such as greater than a predetermined distance threshold or between a first and a second predetermined distance threshold. Similarly, by fitting the formation boundary 340, directional information about the formation boundary 340, such as information about the dip and / or azimuth of the formation boundary 340 (e.g., dip / azimuth along or parallel to the planned well trajectory 350a or dip / azimuth along the gradient of the formation boundary 340), can be derived from the fitting. This information can be used to adjust the dip / azimuth of the planned well trajectory 350a to the adjusted well trajectory 350b, where the dip / azimuth ensures that the distance from the adjusted well trajectory 350b to the formation boundary 340 is within a desired range. The adjusted well trajectory 350b may be subject to constraints, such as sharp turn severity constraints. For example, a minimum curvature scheme may be applied to limit the adjusted well trajectory 350b. Additionally, the calculated adjusted well trajectory 350b may be checked to ensure it meets constraints, such as sharp turn severity constraints. If not, the adjusted well trajectory 350b and / or the adjusted setpoint 370b may be readjusted, for example, by selecting an alternative setpoint at a distance greater than setpoint 370b from the drill bit 360. Once one or more new data points are acquired or received, the process can restart to readjust the well trajectory 350b and / or its inclination / azimuth. Based on the adjusted well trajectory 350b or its inclination / azimuth, directional commands are derived and transmitted to the directional tool to guide BHA 13, including the drill bit 7, toward the direction of the adjusted well trajectory 350b. The process can operate fully or semi-automatically without human operator interaction (e.g., with some supervision from a human operator). Figure 4 A flowchart is depicted for a method 400 for performing geological guidance (such as automated geological guidance) according to one or more embodiments described herein. Method 400 may be performed by any suitable processing system (e.g., processing system 12 or downhole electronics 9) downhole or on the surface, any suitable processing device (e.g., one of processors 21), and / or combinations thereof, or another suitable system or device.

[0052] At box 402, the processing system 12 and / or downhole electronics 9 receive data, such as electromagnetic (EM) data, from downhole components located in the wellbore. In some examples, the received data is filtered to remove erroneous data points. For example, such erroneous data points may represent noise or other inaccurate interference. In some examples, data falling outside a range (e.g., above a high threshold or below a low threshold) is removed.

[0053] At box 404, the processing system 12 and / or downhole electronics 9 perform calculations, such as the inversion of data (which may be, for example, filtered data), to determine one or more distances from various locations at measurement point 310 to the oil-water interface. While guidance along the oil-water interface has been discussed... Figure 4 However, it should be understood that the same method can also be applied along different stratigraphic boundaries (such as the boundary between sandstone and shale layers or fluid-gas contact surfaces). The calculation may include defining one or more layer parameters (e.g., resistivity) for one or more layers (e.g., aquifers) and / or limiting one or more layer parameters for one or more layers to predetermined thresholds, such as predetermined threshold resistivity.

[0054] At box 406, once the distances of the oil-water contact surface from various locations of measurement point 310 have been quantified, the processing system 12 and / or downhole electronics 9 determine the predicted oil-water contact surface (e.g., Figure 3A Oil-water contact area 302 in Figure 3B (Formation boundary 340). Based on the predicted oil-water contact surface, the expected or desired well trajectory can be determined based on the expected distance to the oil-water contact surface (e.g., Figure 3A The expected well trajectory 304 or Figure 3B (Adjusted well trajectory 350b). Using the desired or adjusted well trajectory, target points that can be related to (e.g., near or on) the desired well trajectory can be defined. Figure 3A Prediction point 316 or Figure 3B The adjusted setpoint 370b in the middle). The determination of the predicted oil-water contact area 302 may be based at least in part on one or more distances to the oil-water contact surface. For example, one or more oil-water contact locations may be extrapolated along a defined interval length, such as a polynomial with polynomial coefficients (e.g., a linear regression with slope and offset values). The location points used for extrapolation (e.g., Figure 3A Position points 312a-312e or Figure 3B Position points I-IV in the diagram can be located from the most recent (latest) position point of the detected oil-water contact surface (e.g., Figure 3A Position point 312a or Figure 3BStarting from position point I, work can proceed to a limited number of position points, such as 3 position points, 5 position points, more than 10 position points, more than 20 position points, etc. (e.g., Figure 3A One or more of the following positions: 312b, 312c, 312d, and 312e Figure 3B (One or more of location points II, II, IV). This allows for consideration of the nearest location point while taking into account the differences among a limited number of location points. Using extrapolation parameters, such as polynomial coefficients (e.g., slope and offset), the predicted point can be determined as: Predicted point = (Predicted location of the predicted point) * (Regression slope) + (Offset value).

[0055] At box 408, the processing system 12 and / or downhole electronics 9 adjust the trajectory of the bottomhole assembly (e.g., BHA 13) positioned in the wellbore based at least in part on the predicted oil-water contact surface and the desired well trajectory. For example, one or more downlink commands are sent when calculating the predicted inclination of the oil-water contact surface and the distance from the drill bit. These commands are directional instructions that are calculated and align the well with the desired TVD and inclination measurements. In the example, the current position of BHA 13 is known from directional surveys; similarly, the forward calculated distance from measurement point 310 to drill bit 7 is also known. The desired (i.e., target) inclination and the desired (i.e., target) vertical change from the current position of BHA 13 are also known. Using this known information, the distance and intermediate inclination angle required to achieve the target inclination angle for the desired vertical change within a given sharp turn constraint can be determined.

[0056] This is achieved iteratively by using an additional intermediate point (i.e., intermediate point 314), allowing for inclination changes and calculating the vertical change up to the intermediate point to increase the vertical displacement. If the total vertical change equals the desired vertical change, the intermediate and final point data are reported; otherwise, the calculation is repeated as the intermediate inclination changes increase.

[0057] The processing system 12 and / or downhole electronics 9 can then send downlink commands to adjust the trajectory of the BHA 13, thereby drilling through the wellbore to maintain a desired distance 308 between the BHA 13 and the oil-water contact area or line 302. The desired distance 308 can be based on the oil-water contact surface and actual vertical depth survey data.

[0058] It may also include other processes, and it should be understood that Figure 4 The processes described herein are illustrative, and other processes may be added or existing processes may be removed, modified or rearranged without departing from the scope of this disclosure.

[0059] Exemplary embodiments of this disclosure include or produce various technical features, effects, and / or improvements to the technology. Exemplary embodiments of this disclosure provide technical solutions for automated geosteering based on distances to formation boundaries. These solutions collect and analyze large amounts of electromagnetic data gathered in the wellbore by measuring devices located in the bottomhole assembly, and then invert such data in real-time or near real-time to determine predicted points for the geosteering BHA based on one or more inversion-based distances to the formation boundary. The sheer volume of data, the complexity of performing inversions and determining predicted points, and the real-time or near-real-time nature of adjusting the trajectory of the bottomhole assembly are practically impossible to perform in the human brain. Therefore, the technology described herein represents an improvement to geosteering technology. Drilling decisions can thus be made more accurately and quickly, thereby improving drilling efficiency, reducing non-production time, and increasing hydrocarbon recovery, etc. Specifically, geosteering is improved by obtaining and maintaining the desired distance between the bottomhole assembly and the formation boundary region or line during drilling. This increases hydrocarbon recovery of the hydrocarbon reservoir compared to conventional techniques.

[0060] The following are some of the aforementioned publicly disclosed implementation schemes:

[0061] Implementation Scheme 1: A method for performing automatic geological steering, the method comprising: receiving formation assessment data from a bottom-hole assembly disposed in a wellbore by a processing system; determining location data of formation boundaries by the processing system based on the formation assessment data; extrapolating the location data by the processing system to generate extrapolated location data of the formation boundaries; and adjusting the trajectory of the wellbore based at least in part on the extrapolated location data of the formation boundaries.

[0062] Implementation Scheme 2: The method according to any of the preceding implementation schemes, wherein the extrapolated position data is determined using a polynomial.

[0063] Implementation Scheme 3: The method according to any of the preceding implementation schemes, wherein the location data of the stratigraphic boundary is determined at least in part based on directional data.

[0064] Implementation Scheme 4: The method according to any of the preceding implementation schemes, wherein the direction data is at least one of the dip angle of a portion of the bottom hole assembly, the azimuth angle of a portion of the bottom hole assembly, and the tool face angle of the direction in which the formation boundary is located.

[0065] Implementation Scheme 5: The method according to any of the preceding implementation schemes, wherein the trajectory is adjusted at least in part based on a predetermined threshold of the distance between the adjusted trajectory and the formation boundary.

[0066] Implementation Scheme 6: The method according to any of the preceding implementation schemes, the method further comprising: filtering the stratigraphic assessment data by the processing system to generate filtered stratigraphic assessment data; and determining the location data of the stratigraphic boundary by the processing system based on the filtered stratigraphic assessment data.

[0067] Implementation Scheme 7: The method according to any of the preceding implementation schemes, wherein the formation assessment data is generated at two or more locations within the wellbore.

[0068] Implementation Scheme 8: The method according to any of the foregoing implementation schemes, wherein adjusting the trajectory includes adjusting the setpoint of the control process to guide the bottom hole assembly.

[0069] Implementation Scheme 9: The method according to any of the preceding implementation schemes, wherein the location data is at least one of the distance from the formation boundary to the bottom hole assembly and the true vertical depth of the formation boundary.

[0070] Implementation Scheme 10: The method according to any of the preceding implementation schemes, wherein the extrapolated position data is determined based on the measured depth.

[0071] Implementation Scheme 11. A system for performing automatic geological steering of a wellbore, the system comprising: a bottomhole assembly disposed in the wellbore; and a processing system for executing computer-readable instructions, the computer-readable instructions controlling the processing system to perform operations including: receiving formation assessment data from the bottomhole assembly disposed in the wellbore by the processing system; determining location data of formation boundaries by the processing system based on the formation assessment data; extrapolating the location data by the processing system to generate extrapolated location data of the formation boundaries; and adjusting the trajectory of the wellbore at least in part based on the extrapolated location data of the formation boundaries.

[0072] Implementation Scheme 12: The system according to any of the preceding implementation schemes, wherein the extrapolated position data is determined by a polynomial.

[0073] Implementation Scheme 13: A system according to any of the foregoing implementation schemes, wherein the location data of the stratigraphic boundary is determined at least in part based on directional data.

[0074] Implementation Scheme 14: The system according to any of the foregoing implementation schemes, wherein the direction data is at least one of the dip angle of a portion of the bottom hole assembly, the azimuth angle of a portion of the bottom hole assembly, and the tool face angle of the direction in which the formation boundary is located.

[0075] Implementation Scheme 15: A system according to any of the foregoing implementation schemes, wherein the trajectory is adjusted at least in part based on a predetermined threshold of the distance between the adjusted trajectory and the formation boundary.

[0076] Implementation Scheme 16: According to any of the foregoing implementation schemes, wherein the processing system is further configured to perform operations including: filtering the stratigraphic assessment data by the processing system to generate filtered stratigraphic assessment data; and determining the location data of the stratigraphic boundary by the processing system based on the filtered stratigraphic assessment data.

[0077] Implementation Scheme 17: A system according to any of the foregoing implementation schemes, wherein the formation assessment data is generated at two or more locations within the wellbore.

[0078] Implementation Scheme 18: The system according to any of the foregoing implementation schemes, wherein adjusting the trajectory includes adjusting the setpoint of the control process to guide the bottom hole assembly.

[0079] Implementation Scheme 19: The system according to any of the foregoing implementation schemes, wherein the location data is at least one of the distance from the formation boundary to the bottom hole assembly and the true vertical depth of the formation boundary.

[0080] Implementation Scheme 20: The system according to any of the foregoing implementation schemes, wherein the extrapolated position data is determined based on the measured depth.

[0081] In the context of describing this disclosure (particularly in the context of the appended claims), the terms “an,” “a,” and “the,” and similar designations, should be interpreted to cover both singular and plural forms, unless otherwise specified herein or clearly contradicted by the context. Furthermore, it should be noted that the terms “first,” “second,” etc., used herein do not indicate any order, quantity, or importance, but are used to distinguish one element from another. The modifier “about,” used in conjunction with quantity, includes the stated value and has a meaning determined by the context (e.g., it includes the degree of error associated with a particular quantity of measurement).

[0082] The teachings of this disclosure can be applied to a variety of well operations. These operations may involve treating a formation, fluids residing in the formation, the wellbore, and / or equipment within the wellbore, such as production tubing, with one or more treatment agents. Treatment agents can be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Exemplary treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, corrosion inhibitors, binders, permeability modifiers, drilling mud, emulsifiers, demulsifiers, tracers, flow improvers, etc. Exemplary well operations include, but are not limited to, hydraulic fracturing, production enhancement, tracer injection, cleaning, acidizing, steam injection, water injection, cementing, etc.

[0083] While this disclosure has been described with reference to one or more exemplary embodiments, those skilled in the art will understand that various changes may be made and equivalents may be substituted for elements therein without departing from the scope of this disclosure. Furthermore, many modifications may be made to adapt particular situations or materials to the teachings of this disclosure without departing from the basic scope of this disclosure. Therefore, it is contemplated that this disclosure is not limited to the specific embodiments disclosed as the best mode contemplated for carrying out this disclosure, but rather that this disclosure will include all embodiments falling within the scope of the claims. Additionally, exemplary embodiments of this disclosure have been disclosed in the drawings and detailed descriptions, and although specific terminology has been used, it is used in a general and descriptive sense only, and not for limiting purposes, unless otherwise specified, and the scope of this disclosure is therefore not limited thereto.

Claims

1. A method for performing automatic geosteering, the method comprising: receiving, by a processing system, first formation evaluation data from a bottom hole assembly disposed in a wellbore at a first data point and second formation evaluation data from a bottom hole assembly disposed in a wellbore at a second data point; determining, by the processing system, first position data of a formation boundary from the first formation evaluation data at the first data point and determining, by the processing system, second position data of a formation boundary from the second formation evaluation data at the second data point; determining a first sphere from the first data point and the first position data; determining a second sphere from the second data point and the second position data; determining a position point of the formation boundary on a portion of the first sphere not contained in the second sphere; extrapolating, by the processing system, the position point to generate extrapolated position data of the formation boundary; and maintaining a distance between the bottom hole assembly and the formation boundary by adjusting a trajectory of the wellbore, the adjusting including sending steering instructions to a steering tool to steer the bottom hole assembly, the adjusting implemented based at least in part on the extrapolated position data of the formation boundary.

2. The method of claim 1, wherein the extrapolated position data is determined with a polynomial.

3. The method of claim 2, wherein the extrapolated position data is determined based on a measured depth.

4. The method of claim 1, wherein the extrapolated position data of the formation boundary is obtained along a flat trajectory of the wellbore.

5. The method of claim 1, wherein the extrapolated position data of the formation boundary is determined based at least in part on directional data.

6. The method of claim 5, wherein the directional data is at least one of a tilt angle of a portion of the bottom hole assembly, a azimuth angle of a portion of the bottom hole assembly, and a tool face angle of a direction in which the formation boundary lies.

7. The method of claim 1, wherein the trajectory is adjusted based at least in part on a predetermined threshold of a distance between an adjusted trajectory and the formation boundary.

8. The method of claim 1, the method further comprising: filtering, by the processing system, at least one of the first formation evaluation data and the second formation evaluation data to generate filtered formation evaluation data; and determining, by the processing system, a position point of the formation boundary from the filtered formation evaluation data.

9. The method of claim 1, wherein adjusting the trajectory includes adjusting a set point of a control process to steer the bottom hole assembly.

10. The method of claim 1, wherein at least one of the first position data and the second position data is at least one of a distance from the formation boundary to the bottom hole assembly and a true vertical depth of the formation boundary.

11. A system for performing automatic geosteering of a wellbore, the system for performing automatic geosteering of a wellbore comprising: a bottom hole assembly disposed in the wellbore; and a processing system in communication with the bottom hole assembly. ​ A processing system for executing computer-readable instructions that control the processing system to perform operations comprising: receiving, by the processing system, first formation evaluation data from the bottom hole assembly disposed in the wellbore at a first data point and second formation evaluation data from the bottom hole assembly disposed in the wellbore at a second data point; determining, by the processing system, first position data of a formation boundary from the first formation evaluation data at the first data point and determining, by the processing system, second position data of the formation boundary from the second formation evaluation data at the second data point; determining a first sphere from the first data point and the first position data; determining a second sphere from the second data point and the second position data; determining a position point of the formation boundary on a portion of the first sphere not contained in the second sphere; extrapolating, by the processing system, the position point to generate extrapolated position data of the formation boundary; and adjusting a trajectory of the wellbore to maintain a distance between the bottom hole assembly and the formation boundary, the adjusting including sending steering instructions to a steering tool to steer the bottom hole assembly, the adjusting implemented based at least in part on the extrapolated position data of the formation boundary.

12. The system for performing automatic geosteering of a wellbore of claim 11, wherein the extrapolated position data is determined with a polynomial.

13. The system for performing automatic geosteering of a wellbore of claim 12, wherein the extrapolated position data is determined based on a measured depth.

14. The system for performing automatic geosteering of a wellbore of claim 11, wherein the extrapolated position data of the formation boundary is determined based at least in part on directional data.

15. The system for performing automatic geosteering of a wellbore of claim 14, wherein the directional data is at least one of a tilt angle of a portion of the bottom hole assembly, a azimuth angle of a portion of the bottom hole assembly, and a tool face angle of a direction in which the formation boundary lies.

16. The system for performing automatic geosteering of a wellbore of claim 11, wherein the trajectory is adjusted based at least in part on a predetermined threshold of a distance between the adjusted trajectory and the formation boundary.

17. The system for performing automatic geosteering of a wellbore of claim 11, the system for performing automatic geosteering of a wellbore further configured to perform the additional operations of: filtering, by the processing system, at least one of the first formation evaluation data and the second formation evaluation data to generate filtered formation evaluation data; and determining, by the processing system, a position point of the formation boundary from the filtered formation evaluation data.

18. The system for performing automatic geosteering of a wellbore of claim 11, wherein adjusting the trajectory includes adjusting a set point of a control process to steer the bottom hole assembly.

19. The system for performing automatic geosteering of a wellbore of claim 11, wherein at least one of the first location data and the second location data is at least one of a distance from the formation boundary to the bottom hole assembly and a true vertical depth of the formation boundary.

20. The system for performing automatic geosteering of a wellbore of claim 11, wherein the computer readable instructions further control the processing system to generate the extrapolated location data of the formation boundary along a flattened trajectory of the wellbore.

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