AUTOMATED RESERVOIR NAVIGATION

Abstract

Examples described herein provide a computer-implemented method for automated reservoir navigation that includes receiving a reference indicative of a reservoir architecture. The method further includes determining a discrepancy between a well plan and the reference. The method further includes evaluating the discrepancy relative to a discrepancy threshold. The method further includes, responsive to determining that the discrepancy fails to satisfy the discrepancy threshold, causing a bottom hole assembly to navigate based at least in part on the discrepancy.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Ser. No. 63/326,217 filed Mar. 31, 2022, the disclosure of which is incorporated herein by reference in its entirety.

BACKGROUND

Embodiments described herein relate generally to downhole exploration and production efforts in the resource recovery industry and more particularly to techniques for automated reservoir navigation.

Downhole exploration and production efforts involve the deployment of a variety of sensors and tools. The sensors provide information about the downhole environment, for example, by collecting data about temperature, density, saturation, and resistivity, among many other parameters. This information can be used to control aspects of drilling and tools or systems located in the bottom hole assembly, along the drillstring, or on the surface.

SUMMARY

In one exemplary embodiment, a computer-implemented method for automated reservoir navigation is provided. The method includes receiving a reference indicative of a reservoir architecture. The method further includes determining a discrepancy between a well plan and the reference. The method further includes evaluating the discrepancy relative to a discrepancy threshold. The method further includes, responsive to determining that the discrepancy fails to satisfy the discrepancy threshold, causing a bottom hole assembly to navigate based at least in part on the discrepancy.

In another exemplary embodiment a system includes a bottom hole assembly disposed in a wellbore and a processing system for executing computer readable instructions. The computer readable instructions control the processing system to perform operations. The operations include receiving a reference indicative of a reservoir architecture. The operations further include determining an offset between a well plan and the reference. The operations further include determining a relative dip between the well plan and the reference. The operations further include determining a drainage area between the well plan and the reference; evaluating the offset, the relative dip, and the drainage area relative to respective offset, relative dip, and drainage area thresholds. The operations further include, responsive to determining that at least one of the offset, the relative dip, and the drainage area fails to satisfy one or more of the respective offset, relative dip, or drainage area thresholds, causing the bottom hole assembly to navigate based at least in part on at least one of the offset, the relative dip, or the drainage area.

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

Additional technical features and benefits are realized through the techniques of the present invention. Embodiments and aspects of the invention are described in detail herein and are considered a part of the claimed subject matter. For a better understanding, refer to the detailed description and to the drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring now to the drawings wherein like elements are numbered alike in the several figures:

FIG. 1 depicts a cross-sectional view of a wellbore operation system according to one or more embodiments described herein;

FIG. 2 depicts a block diagram of the processing system of FIG. 1, which can be used for implementing the present techniques herein according to one or more embodiments described herein;

FIG. 3 depicts a block diagram of a system for automated reservoir navigation according to one or more embodiments described herein;

FIG. 4A depicts a flow diagram of a method for automated target discrepancy review according to one or more embodiments described herein;

FIG. 4B depicts a flow diagram of a method for ad-hoc target discrepancy review according to one or more embodiments described herein;

FIG. 5 depicts a flow diagram of a method for automated reservoir navigation according to one or more embodiments described herein;

FIGS. 6A-6F depict schematic views of a well path according to one or more embodiments described herein;

FIG. 7 depicts a wireframe of an interface for automated reservoir navigation according to one or more embodiments described herein; and

FIGS. 8A and 8B depict a target line triggering approach according to one or more embodiments described herein.

DETAILED DESCRIPTION

Modern bottom hole assemblies (BHAs) are composed of several distributed components, such as sensors and tools, with each component performing data acquisition and/or processing of a special purpose. An example of one type of data acquired can include electromagnetic data.

Wellbores are drilled into a subsurface to produce hydrocarbons and for other purposes. In particular, FIG. 1 depicts a cross-sectional view of a wellbore operation system 100, according to aspects of the present disclosure. In traditional wellbore operations, logging-while-drilling (LWD) measurements are conducted during a drilling operation to determine formation rock and fluid properties of a formation 4. Those properties are then used for various purposes such as estimating reserves from saturation logs, defining completion setups, etc. as described herein.

The system and arrangement shown in FIG. 1 is one example to illustrate the downhole environment. While the system can operate in any subsurface environment, FIG. 1 shows a carrier 5 disposed in a borehole 2 penetrating the formation 4. The carrier 5 is disposed in the borehole 2 at a distal end of the borehole 2, as shown in FIG. 1.

As shown in FIG. 1, the carrier 5 is a drill string that includes a bottom hole assembly (BHA) 13. The BHA 13 is a part of the operation system 100 and includes drill collars, stabilizers, reamers, and the like, and the drill bit 7. In examples, the drill bit 7 is disposed at a forward end of the BHA 13. The BHA 13 also includes sensors 10 (e.g., including, but not limited to, measurement tools 11) and electronic components (e.g., downhole electronic components 9). The measurements collected by the measurement tools 11 can include measurements related to drill string operations, for example. BHA 13 also includes a steering tool configured to steer BHA 13 and drill bit 7 into a desired direction. The steering tool may receive steering commands based on which it creates steering forces to push or point drill bit 7 into the desired direction. Operation system 100 is configured to conduct drilling operations such as rotating the drill string and, thus, the drill bit 7. A drilling rig 8 also pumps drilling fluid through the drill string 5 in order to lubricate the drill bit 7 and flush cuttings from the borehole 2. The measurement tools 11 and downhole electronic components 9 are configured to perform one or more types of measurements in an embodiment known as logging-while-drilling (LWD) or measurement-while-drilling (MWD) according to one or more embodiments described herein.

Raw data is collected by the measurement tools 11 and transmitted to the downhole electronic components 9 for processing. The data can be transmitted between the measurement tools 11 and the downhole electronic components 9 by an electrical conduit 6, such as a wire (e.g. a powerline) or a wireless link, which transmits power and/or data between the measurement tools 11 and the downhole electronic components 9. Power is generated downhole by a turbine-generation combination (not shown), and communication to the surface 3 (e.g., to a processing system 12) is cable-less (e.g., using mud pulse telemetry, electromagnetic telemetry, etc.) and/or cable-bound (e.g., using a cable to the processing system 12, e.g. by wired pipes). The data processed by the downhole electronic components 9 can then be telemetered to the surface 3 for additional processing or display by the processing system 12.

Drilling control signals can be generated by the processing system 12 (e.g., based on the raw data collected by the measurement tools 11) and conveyed downhole or can be generated within the downhole electronic components 9 or by a combination of the two according to embodiments of the present disclosure. The downhole electronic components 9 and the processing system 12 can each include one or more processors and one or more memory devices. In alternate embodiments, computing resources such as the downhole electronic components 9, sensors, and other tools can be located along the carrier 5 rather than being located in the BHA 13, for example. The borehole 2 can be vertical as shown or can be in other orientations/arrangements (see, e.g., FIG. 3A, FIG. 3B).

It is understood that embodiments of the present disclosure are capable of being implemented in conjunction with any other suitable type of computing environment now known or later developed. For example, FIG. 2 depicts a block diagram of the processing system 12 of FIG. 1, which can be used for implementing the techniques described herein. In examples, processing system 12 has one or more central processing units 21a, 21b, 21c, etc. (collectively or generically referred to as processor(s) 21 and/or as processing device(s) 21). In aspects of the present disclosure, each processor 21 can include a reduced instruction set computer (RISC) microprocessor. Processors 21 are 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 system bus 33 and can include a basic input/output system (BIOS), which controls certain basic functions of processing system 12.

Further illustrated are an input/output (I/O) adapter 27 and a network adapter 26 coupled to system bus 33. I/O adapter 27 can be a small computer system interface (SCSI) adapter that communicates with a memory, such as a hard disk 23 and/or a tape storage device 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 34. Operating system 40 for execution on the processing system 12 can be stored in mass storage 34. The network adapter 26 interconnects system bus 33 with an outside network 36 enabling processing system 12 to communicate with other systems.

A display (e.g., a display monitor) 35 is connected to system bus 33 by display adaptor 32, which can include a graphics adapter to improve the performance of graphics intensive applications and a video controller. In one aspect of the present disclosure, adapters 26, 27, and/or 32 can be connected to one or more I/O busses that are connected to 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 the Peripheral Component Interconnect (PCI). Additional input/output devices are shown as connected to system bus 33 via user interface adapter 28 and display adapter 32. A keyboard 29, mouse 30, and speaker 31 can be interconnected to system bus 33 via user interface adapter 28, which can include, for example, a Super I/O chip integrating multiple device adapters into a single integrated circuit.

In some aspects of the present disclosure, processing system 12 includes a graphics processing unit 37. Graphics processing unit 37 is a specialized electronic circuit designed to manipulate and alter memory to accelerate the creation of images in a frame buffer intended for output to a display. In general, graphics processing unit 37 is very efficient at manipulating computer graphics and image processing and has a highly parallel structure that makes it more effective than general-purpose CPUs for algorithms where processing of large blocks of data is done in parallel.

Thus, as configured herein, processing system 12 includes processing capability in the form of processors 21, storage capability including system memory (e.g., RAM 24 and mass storage 34), input means such as keyboard 29 and mouse 30, and output capability including speaker 31 and display 35. In some aspects of the present disclosure, a portion of system memory (e.g., RAM 24 and mass storage 34) collectively store an operating system to coordinate the functions of the various components shown in processing system 12.

According to examples described herein, techniques for automated reservoir navigation are provided. During reservoir navigation (also referred to as “geosteering”), it may be desirable to maintain a certain distance between the BHA and a distinct formation feature, such as a formation boundary within formation 4, e.g. the boundary between two different formations (e.g. sand and shale), an oil-water contact, or a fluid-gas contact within the formation. A boundary between two different formations (e.g. sand and shale) is a surface in the formation 4 where the two formations come into contact. Similarly, an oil-water contact or a fluid-gas contact is a surface in the formation 4 where oil and water or fluid and gas come into contact in a formation or where oil saturation, water saturation, and/or gas saturation have a distinct value, such as a pre-defined value. Typically, the oil-water contact denotes a surface having oil above and water below and the fluid-gas contact denotes a surface having gas above and fluid below. In other instances, the contact between two fluids may be transitional in a way that the change from one fluid type into another fluid type is not representable by a sharp contrast but rather by a gradational change in saturation. Formation features like formation boundaries (e.g. boundaries between two different formations, oil-water contacts, or fluid-gas contacts) can vary in space and may not be plain areas.

In order to achieve optimal hydrocarbon recovery from a hydrocarbon reservoir, it may be desirable to drill a wellbore a desired distance away from a formation boundary. Accordingly, the techniques for automated reservoir navigation described herein provide for steering a BHA at least in part based on metrics that can be used to cause the BHA to navigate relative to a reference associated with a reservoir architecture, such as a formation boundary, etc. Examples of such metrics include offset, relative dip, and drainage area. The “offset” is an offset between a well plan and the reference associated with the reservoir architecture. The “relative dip” is a relative dip between the well plan and the reference associated with the reservoir architecture. The “drainage area” is a drainage area between the well plan and the reference associated with the reservoir architecture. One or more embodiments described herein provide for determining these metrics (e.g., offset, relative dip, and drainage area) with respect to a well plan (e.g., a prediction (extrapolated points) or a planned trajectory) and the reference associated with the reservoir architecture and using these metrics to make navigation decisions to cause the BHA to navigate through a formation.

Recent developments towards automating wellbore placement aim at navigating a wellbore at an ideally constant target offset (distance) away from an oil-water contact. The oil-water contact is a specific incidence of a fluid or lithological boundary/reference, which can be mapped or tracked using an inversion approach on using resistivity data. Current approaches to automated wellbore placement cause undulating trajectories, which do not seem to be in phase with the oil-water contact and can cause early water breakthrough due to the proposed trajectory coming too close to the oil-water contact.

One or more embodiment described herein address these and other shortcomings of the prior art by using offset, relative dip, and drainage area metrics to control a BHA. For example, the metrics can be used to cause the BHA to navigate based at least in part on one or more of the offset, the relative dip, or the drainage area.

FIG. 3 depicts a block diagram of a system 300 for automated reservoir navigation according to one or more embodiments described herein. The system 300 can be performed using one or more engines, systems, components, etc. configured and arranged as shown, although other configurations and arrangements are also possible. One or more of the various engines, systems, components, etc. described regarding FIG. 3 can be implemented as instructions stored on a computer-readable storage medium, as hardware modules, as special-purpose hardware (e.g., application specific hardware, application specific integrated circuits (ASICs), application specific special processors (ASSPs), field programmable gate arrays (FPGAs), as embedded controllers, hardwired circuitry, etc.), or as some combination or combinations of these. According to aspects of the present disclosure, the engine(s) described herein can be a combination of hardware and programming. The programming can be processor executable instructions stored on a tangible memory, and the hardware can include a processing device (e.g., the processor 21a of FIG. 2) for executing those instructions. Thus a system memory (e.g., the RAM 24 and/or the ROM 22 of FIG. 2) can store program instructions that when executed by the processing device implement the engines described herein. Other engines can also be utilized to include other features and functionality described in other examples herein.

A data acquisition system 320 acquires data from one or more sensors (e.g., the measurement tools 11) associated with the BHA 13. The data can be in the form of real-time (or near-real-time) data. The data acquisition system 320 provides the data as real-time (or near-real-time) LWD/MWD data to the reservoir mapping engine 310. The reservoir mapping engine 310 generates a reference for a reservoir architectural feature (e.g., oil-water contact, oil-gas contact, lithological boundary, e.g., a lithological caprock boundary, formation boundary or layer boundary, such as a boundary between layers with different formation characteristics (e.g., different gamma activity, magnetic, electric, or acoustic properties, or other characteristics that may be measured or logged while drilling)). Generating the reference may include defining/determining one or more locations of the reservoir architectural feature. Locations of reservoir architectural feature may be measured (such as by a distance from the BHA on a well path) or may be interpolated or extrapolated based on measured locations of reservoir architectural features. Defining/determining one or more locations of a reservoir architectural feature may be done by utilizing one or more inversion methods known in the art. For example, one or more locations of a reservoir architectural feature may be defined/determined by modeling a measurement response of a sensor (e.g., a resistivity sensor, a gamma sensor, an acoustic sensor, etc.) for a hypothetical position of the reservoir architectural feature. The modeled measurement response is then compared with the actual measurement response of the sensor and, in case of a mismatch between the modeled and the actual measurement response (e.g., in case that the difference or the ratio of the modeled and the actual measurement response exceeds a predefined threshold), the hypothetical position of the reservoir architectural feature is varied or amended and a measurement response of the sensor is modeled again with the varied or amended position of the reservoir architectural feature and compared to the actual measurement response of the sensor. This process is repeated until the mismatch of the modeled and the actual measurement response is acceptably low (e.g., below a predefined threshold). Those skilled in the art will appreciate that the inversion may utilize pre-knowledge of the reservoir such as, but not limited to, position of faults, oil-water contact, layer boundaries, etc. Such pre-knowledge may come from pre-drilled wells or investigations from the earth's surface, such as surface seismic investigations. Pre-knowledge of the reservoir may be used to define the hypothetical position of the reservoir architectural feature or may be used to limit the range in which the reservoir architectural feature may be varied during the inversion process. Formation evaluation (FE) log interpretation is performed at the reservoir mapping engine 310, which can be guided, for example, by petrophysicist 301. Reservoir navigation services (RNS) engineer 302 can review and approve the reference, which is then input into the navigation engine 312. The navigation engine 312, which is described in further detail herein (see, e.g., FIGS. 5 and 6A-6F), provides navigational information/instructions (e.g., actual position, such as actual depth information, actual inclination, or actual azimuth of the BHA 13 or the drill bit 7 and/or target position, such as target depth information, target inclination or target azimuth of the BHA 13 or the drill bit 7, etc.). Operations (OPS) engineer 303 can review and approve the navigational information/instructions using the navigation engine 312. The navigational information/instructions are then provided to the dynamic trajectory design engine 314, which computes and provides a well plan and constraints as well as well targets (which can be reviewed and approved by well planner 304) to the dynamic trajectory control engine 316. Well targets (or simply targets) may include positions that the well trajectory is supposed to enter in the future. For example, a target position may be defined in space at some distance of drill bit 7 and the BHA 13 and is then steered to drill through that target position. Targets may also include one or more target positions in space or a continuous range of target positions in space, for example when defined by a target line (for example a straight target line). In case of one or more discrete target positions, targets may be defined by their coordinates (e.g., x,y,z-coordinates, or depth, inclination, and azimuth). In case of a range of target positions in space, targets may be defined by equations and their parameters (for example, a straight target line may be defined by the coordinates of one target position on the straight target line and the target slope of the straight target line). Targets may not only be defined with respect to positions but also with respect to other metrics (for example, with respect to offset, relative dip, or drainage area). For example, a target offset may be defined and the BHA 13 is then steered to drill in a way that the measured offset matches the target offset with a predefined accuracy (e.g., in a way that the difference and/or ratio of target offset and measured offset is below a predefined threshold). As another example, a target relative dip between a reference and the well trajectory may be defined and the BHA 13 is then steered to drill in a way that the measured relative dip matches the target relative dip with a predefined accuracy (e.g., in a way that the difference and/or ratio of target relative dip and measured relative dip is below a predefined threshold). As yet another example, a target drainage area between a reference and the well trajectory may be defined and the BHA 13 is then steered to drill in a way that the measured drainage area matches the target drainage area with a predefined accuracy (e.g., in a way that the difference and/or ratio of target drainage area and measured drainage area is below a predefined threshold). Directional driller 305 can review and approve the well plan and constraints as well as well targets. Once approved, the dynamic trajectory control engine 316 sends steering downlinks with steering information/instructions to the BHA 13 as encoded steering downlinks via downlinking system 318. Driller 306, in some cases, can reject the downlinks as shown in FIG. 3.

The techniques described herein (see, e.g., the method 500 of FIG. 5) can be implemented in the context of an automated wellbore placement service, such as using the system 300 of FIG. 3. Examples of operating modes for automated reservoir navigation advice are shown in FIGS. 4A and 4B.

FIG. 4A depicts a flow diagram of a method 400 for automated target discrepancy review according to one or more embodiments described herein. At block 402, the system 300 monitors a distance to the next connection. That is, during the drilling process carrier 5 comprises a plurality of drill pipes. One or more drill pipes are typically pre-connected to form a so-called stand. Stands will be consecutively added to carrier 5 as drill bit 7 and BHA 13 progress into formation 4 to form borehole 2. To add a stand to carrier 5, the drilling process needs to be progressed such that the carrier 5 is almost completely lowered into borehole 2. Rotation of drill bit 7 and flow of drilling is then halted to allow adding a new stand to carrier 5. This allows making a connection between the new stand and the carrier 5 so that the new stand becomes part of carrier 5. Adding a stand by making a connection between a new stand and carrier 5 is done every time the borehole 2 is drilled further such that the carrier 5 is almost completely lowered into the borehole. At block 404, the system 300 continuously monitors a discrepancy between metrics (e.g., the difference or ratio of measured offset, relative dip, or drainage area and respective measured offset, relative dip, or drainage area). “Continuously monitoring” in this context means performing periodically repeated measurements. When the distance to the next connection falls under a preselected threshold, (for example, when the distance to the next connection is below 1 meter) and if the discrepancy between chosen metrics exceeds or falls below the predefined thresholds, system 300 sends out a corresponding notification so that the discrepancy can be reviewed at block 406 using a target to reference, offset, relative dip, and/or drainage area at block 408. At decision block 410, it is determined whether to change the well plan based on the evaluation at block 406, which can be checked and eventually confirmed or rejected by an engineer 412 (e.g., the RNS engineer 302 of FIG. 3). If the decision is not to change the well plan, monitoring continues at block 402. If, however, it is decided at decision block 410 to change the well plan, a new target can be defined at block 414, and a dynamic trajectory design can begin at block 414 (see dynamic trajectory design engine 314 of FIG. 3).

FIG. 4B depicts a flow diagram of a method 420 for ad-hoc target discrepancy review according to one or more embodiments described herein. At block 422, the processing system 300 performs continuous discrepancy monitoring at block 422. It is then determined at decision block 424 whether the discrepancy exceeds or falls below predefined thresholds for offset, relative dip, and/or drainage area based on values at block 426. If the discrepancy does not exceed or fall below predefined thresholds, monitoring continues at block 422. If, however, it is decided at decision block 424 that the discrepancy exceeds or falls below threshold(s), the method proceeds to block 428 and an alert is issued. At block 430, new targets can be defined (e.g., automatically, manually, etc.), and at block 432, a dynamic trajectory design can begin (see dynamic trajectory design engine 314 of FIG. 3).

FIG. 5 depicts a flow diagram of a method for automated reservoir navigation according to one or more embodiments described herein. The method 500 can be performed by any suitable processing system downhole or on surface (e.g., the processing system 12, the downhole electronic components 9, a cloud computing node of a cloud computing environment), any suitable processing device (e.g., one of the processors 21), and/or combinations thereof or another suitable system or device. FIG. 5 is now described in more detail with reference to FIGS. 3 (as described above) and 6A-6F, which depict schematic views of a well path according to one or more embodiments described herein.

The method 500 provides for monitoring metrics, such as the position of a wellbore relative to a reservoir architecture, determining any discrepancy therebetween, and providing navigation advice to reduce the discrepancy. This approach is applicable to multiple drilling scenarios, such as a change in an offset to a reference, a change in an inclination/relative dip between a reference and a well plan, a change in an offset and an inclination in upwards and downwards total vertical depth (TVD) direction, a change in a lithology so that a reference is missing for a section of a wellbore, stringer intervals, undulations and inclination changes, navigation along two references, and the like. In some examples, the navigation advice is “stable advice” in that it holds for an elongated drilling distance. In some examples, frequently fluctuating advice is reduced so as to not overly trigger navigation advice. In some implementations, the method 500 is applicable to a generate navigation advice for a single reference. However, in some examples, multiple references can be used.

Turning now briefly to FIG. 6A, a schematic view of a well path 601 and a reference 602 is provided. In this case, the reference is an oil-water contact boundary, but it should be appreciated that other reservoir architectures are also possible. For example, reference 602 could be a layer boundary, such as a boundary between layers with different formation characteristics (e.g., different gamma activity, magnetic, electric, or acoustic properties, or other characteristics that may be measured or logged while drilling). Notably, in the examples of FIGS. 6A-6F, the well path 601 and the predicted well paths 601a, 603 are one-dimensional structures in 3D space while the reference 602 is a two-dimensional structure in 3D space. The well path 601 is determined by one or more last directional surveys as known in the art, for example directional surveys that may comprise measured directional information, such as azimuth, inclination and/or toolface and depth information, such as total vertical depth or measured depth (distance from drilling rig 8 along the borehole 2). Depending on the distance from the sensors providing the directional information to the drill bit 7, the directional information may be known as near-bit azimuth, near-bit inclination, etc. Directional surveys may be determined at discrete locations on well path 601 (indicated by black dots in FIGS. 6A-6F) or may be determined continuously. If directional surveys are determined at discrete locations, well path 601 may be determined by interpolation between those discrete locations. Depending on the distance from the sensors providing the directional information to the drill bit 7, the directional information may be known as near-bit azimuth, near-bit inclination, etc. The well path 601 includes a well path 601a that is drilled after the last directional survey is determined. Further, the schematic view 600 includes a well path prediction 603. It should be appreciated that the well path 601a and the well path prediction 603 are both predictions. The well path 601a is a prediction to the drill bit 7 at the time when the directional measurements are taken within BHA 13 and the well path prediction 603 is a prediction of the well path ahead of the drill bit 7. In one or more examples, the well path 601a can include a predicted well path from a sensor position within BHA 13 to the position of drill bit 7 (point 604) and prediction ahead of bit (e.g., the well path prediction 603). The difference of well path predictions 601a and 603 is that the well path that corresponds to well path prediction 601a is already drilled although yet unknown while the well path that corresponds to well path prediction 603 does not even exist in the situations as shown in FIGS. 6a-6F. Well path predictions 601a, 603 may be determined by extrapolating information of well path 601 to point 604 or ahead of drill bit 7 or by modeling the predicted well path 601a, 603 by suitable models that are capable to predict behavior of BHA 13 and predicted well path 601a, 603 when applying certain steering parameter to BHA 13. A point 604 on the well path 601 represents the position of drill bit 7. A sensor offset 605 represents a distance along the BHA 13 between a measurement point or sensor location on the BHA 13 and the drill bit 7. The well path 601a can also include an actual well path or a planned well path, in various embodiments.

With continued reference to FIG. 5, at block 502, the processing system 12, using the navigation engine 312, receives a reference (e.g., the reference 602) indicative of a reservoir architecture. For example, the reference indicative of a reservoir architecture may be an oil-water contact, an oil-gas contact, a lithological boundary (e.g., a lithological caprock boundary, a formation boundary or layer boundary, such as a boundary between layers with different formation characteristics (e.g., different gamma activity, magnetic, electric, or acoustic properties, or other characteristics that may be measured or logged while drilling)). According to one or more embodiments described herein, the reference 602 is determined from surface data and/or downhole data. Those skilled in the art will appreciate that said surface data and/or downhole data may include data that is measured by sensors within BHA 13 and sensors that are included in drilling rig 8. Surface data and/or downhole data may also comprise pre-knowledge of the reservoir, such as but not limited to position of faults, oil-water contact, layer boundaries, etc. Such pre-knowledge may come from pre-drilled wells or investigations from the earth's surface, such as surface seismic investigations. For example, the BHA 13 can include one or more sensors (e.g., measurement tools 11 in BHA 13) to collect data downhole in the borehole (or wellbore) 2. The data can be any suitable data, such as lithology data, acoustic data, rheological data, resistivity data, or the like, or any combination thereof.

At block 504, the processing system 12, using the navigation engine 312, determines an offset (i.e., a distance) between a well plan, an actual well path 601, or a predicted well path 601a, 603 and the reference (e.g., the reference 602). With reference to FIG. 6B, the reference 602 is an oil-water contact and offset 610 is shown as ΔOWC. The offset represents a distance between a well path 601, a predicted well path 601a, 603, or a planned well path (e.g., a position on well path 601, predicted well path 601a, 603, planned well path) and a reference (e.g., the reference 602). This approach is applicable to offset-type user scenarios, for example. The offset can be determined at a measurement point (e.g., a sensor location) of the BHA 13, at the drill bit 7, at a defined distance ahead of the bit 7, or any other desired position along well path 601. For bit-ahead determination for prediction, an extrapolation technique, such as a linear regression can be used. For example, commonly-owned U.S. patent application Ser. No. 17/200,207 describes such an extrapolation technique and is incorporated by reference herein in its entirety. Using the offset approach is applicable whenever geology references from inversion and the wellbore shows a smooth, well-defined behavior, for example. According to an example, a desired offset (or “offset threshold”) can be defined, such as 3 meters.

With continued reference to FIG. 5, at block 506, the processing system 12, using the navigation engine 312, determines a relative dip between the well plan (e.g., the well path 601) and the reference (e.g., the reference 602). As shown in FIG. 6C, the relative dip 620 (shown as “a”) represents the angular difference between the inclination of a reference 602 and the inclination of well path 601, predicted well path 601a, 603, or planned well path applicable to inclination-change type scenarios, for example. The relative dip can be determined from orientations/directions/slopes of the well path (e.g., the well path 601, predicted well path 601a, 603, or planned well path) and the reference (e.g., the reference 602) over regression intervals L2 622 (corresponding to the distance between sensor and drill bit 7) and L3 623 using, for example, linear regression. It is important to note that the determination of the relative dip 620 between well path 601, predicted well path 601a, 603, or planned well path and reference 602 cannot be made based on a single measurement of the distance from BHA 13 to reference 602. To determine the inclination of reference 602, at least two measurement of the distance from BHA 13 to reference 602 have to be used to calculate inclination of reference 602 and relative dip between well path 601, predicted well path 601a, 603, or planned well path and reference 602. For example, a range of measurements of the distance from BHA 13 to reference 602 over a predefined interval of reference 602 may be used to calculate inclination of reference 602 and relative dip between well path 601, predicted well path 601a, 603, or planned well path and reference 602. By using the relative dip, better-behaving navigational advice can be provided because the advice is based on trends as opposed to single offsets, for example. According to an example, a desired relative dip (or “relative dip threshold”) can be defined, such as +/−2 degrees.

With continued reference to FIG. 5, at block 508, the processing system 12, using the navigation engine 312, determines a drainage area 630 between a well plan and the reference. With reference to FIG. 6D, the drainage area 630 represents the distance between a well path (e.g., the well path 601) and a geological reference (e.g., the reference 602) integrated over a certain (e.g. predefined) portion of well path 601 or predicted well path 601a, 603 to monitor an expected drainage behavior of a well applicable to undulating/fluctuating/tortuous reference line scenarios. That is, over the predefined portion of well path 601 or predicted well path 601a, 603, the distance between well path 601 or predicted well path 601a, 603 and reference 602 will be measured and multiplied with the distance of the sensor location to the previous location where the distance between well path 601 or predicted well path 601a, 603 and reference 602 was measured to determine a portion of the drainage area 630. The distance between well path 601 or predicted well path 601a, 603 and reference 602 may be the shortest distance between well path 601 or predicted well path 601a, 603 and reference 602 at the sensor location. However, other options to define the distance are also possible. For example, the distance between well path 601 or predicted well path 601a, 603 and reference 602 may be a difference between TVD of the well path 601 or predicted well path 601a, 603 at the sensor location and the TVD of the reference 602 at a point that has the same horizontal coordinates as the sensor location. Summing the portions of the drainage area 630 within the predefined portion of well path 601 or predicted well path 601a, 603 will then allow to determine the drainage area 630. By this definition of the drainage area 630, the drainage area 630 corresponds to the hatched area in FIGS. 6D-6E. The drainage area 630 can be determined by summing the portions of the drainage area 630 within the predefined portion of well path 601 or predicted well path 601a, 603 (e.g., within a predefined distance interval, such as 10 meters, 30 meters, a stand, three stands, 100 meters, or even longer) L4 634. According to an example, a desired drainage area (or “drainage area threshold”) can be defined. Similar to the determination of the relative dip 620 between well path 601, predicted well path 601a, 603, the determination of the drainage area 630 between well path 601, predicted well path 601a, 603, or planned well path and reference 602 cannot be made based on a single measurement of the distance from BHA 13 to reference 602. To determine the drainage area 630, at least two measurement of the distance from BHA 13 to reference 602 are used to calculate the drainage area 630 between well path 601, predicted well path 601a, 603, or planned well path and reference 602. In some examples, the predefined distance interval L4 634 can be based, for example, on how undulating or tortuous the reference 602 is. For example, if a reference 602 is highly undulating (has a high tortuosity), the predefined distance interval L4 634 can be longer compared to a case when reference 602 is less undulating (has a smaller tortuosity). Undulating behavior or tortuosity of reference 602 can be determined while drilling progresses and distance interval L4 634 can be adjusted while drilling based on the determined undulating behavior or tortuosity of reference 602. For example, if during drilling based on the measurements of distance from BHA 13 to reference 602, it can be determined that the undulating behavior or tortuosity of reference 602 increased (decreased) over a predefined interval of reference 602 (such as over the predefined distance interval L4 634, for example), the predefined distance interval L4 634 can be increased (decreased) to adapt to the determined undulating behavior or tortuosity of reference 602. This provides for making navigational corrections when significant deviations occur (e.g., when the measured values exceed or fall below their corresponding thresholds) while providing for stability when navigating along smaller-scale undulating references (e.g., when the measured values do not exceed or fall below their corresponding threshold(s)).

According to one or more embodiments described herein, as shown in FIG. 6E, a lower bound 640 can be set for reference 602 (e.g., undulating or tortuous reference 602) to provide for a fixed distance (e.g., minimum or maximum distance between the reference 602 and well path 601, predicted well path 601a, 603, or planned well path over a predefined interval of the reference 602 and well path 601, predicted well path 601a, 603, or planned well path) when determining the drainage area 630. The lower bound 640 can be a horizontal, for example a horizontal at a distance from the sensor location that corresponds to a smallest or largest measured distance from sensor location to reference 602 along a predefined portion of well path 601a, or a percentage of the smallest/largest measured distance from sensor location to reference 602 along a predefined portion of well path 601a, for example. This represents the lowest bound of the drainage area. This approach is beneficial for undulating or tortuous references 602 by providing that a minimum distance is maintained between the reference 602 and the well path 601, predicted well path 601a, 603, or planned well path.

As shown in FIG. 6F, the offset 610, relative dip 620, and drainage area 630 determinations described with respect to blocks 504, 506, and 508 of FIG. 5 are applicable in scenarios with multiple references. For example, FIG. 6F shows the well path 601 and two references: 650a and 650b. In this example, the reference 650a is a lithological boundary that also represents an oil-gas contact and the reference 650b is a boundary of oil-water contact. In such a scenario, a first offset, a first relative dip, and a first drainage area may be determined with respect to the first reference 650a and a second offset, a second relative dip, and a second drainage area may be determined with respect to the second reference 650b. In block 512 (as described below) BHA 13 may then be navigated based on one or more of the first and second offset, first and second relative dip, and first and second drainage area.

With continued reference to FIG. 5, at block 510, the processing system 12 using the navigation engine 312, evaluates the offset, the relative dip, and the drainage area relative to respective offset, relative dip, and drainage area thresholds. For example, the offset is compared to the offset threshold, the relative dip is compared to the relative dip threshold, and the drainage area is compared to the drainage area threshold. As an example, the offset is determined not to satisfy the offset threshold when the offset exceeds or falls below the offset threshold. It is noted that a threshold can be a discrete value or a range of values, e.g. a plurality of discrete values or an interval of values. As another example, the relative dip is determined not to satisfy the relative dip threshold when the relative dip falls outside an angular range defined by the relative dip threshold. As yet another example, the drainage area is determined not to satisfy the drainage area threshold when the drainage area exceeds or falls below the drainage area threshold.

When one or more of the thresholds are not satisfied, it may be desirable to cause the BHA 13 to navigate differently, such as to change its position relative to the well path 601, predicted well path 601a, 603, or planned well path. At block 512, responsive to determining that at least one of the offset, the relative dip, and the drainage area fails to satisfy one or more of the respective offset, relative dip, or drainage area thresholds, the processing system 12 (e.g., using one or more of the navigation engine 312, the dynamic trajectory design engine 314, the dynamic trajectory control engine 316, and/or the downlinking system 318) causes the BHA 13 to navigate based at least in part on at least one of the offset, the relative dip, or the drainage area. The trajectory control engine 316 can be a proportional integral derivative controller, in various embodiments. Alternatively, the processing system 12 can include a proportional integral derivative controller for controlling the relative dip and/or the drainage area. For example, if at block 510 it is determined that the offset threshold is not satisfied (e.g., the determined offset from block 504 exceeds the offset threshold), the BHA 13 may be caused to navigate closer to the reference to reduce the offset. Similarly, if at block 510 it is determined that the relative dip threshold is not satisfied (e.g., the determined relative dip from block 506 falls outside an angular range defined by the relative dip threshold), the BHA 13 may be caused to navigate to reduce the relative dip. If at block 510 it is determined that the drainage area threshold is not satisfied (e.g., the determined drainage area from block 508 exceeds the drainage area threshold), the BHA 13 may be caused to navigate closer to the reference to reduce the drainage area. Combinations of these are also possible. As an example, two or even three of the metrics (e.g., offset, relative dip, and drainage area) may exceed their respective thresholds. In such cases, the BHA 13 may be caused to navigate to satisfy each of the metrics. Causing the BHA 13 to navigate can include generating a steering instruction and sending the steering instruction via telemetry to BHA 13 (e.g., as a steering downlink via downhole telemetry to the BHA 13).

Additional processes also may be included, and it should be understood that the process depicted in FIG. 5 represents an illustration, and that other processes may be added or existing processes may be removed, modified, or rearranged without departing from the scope of the present disclosure. According to one or more embodiments described herein, the method 500 is applicable to non-geometric references for lower-tier reservoir navigation services automation. An example of such a low-tier service includes navigating along simple formation evaluation (FE) property such as a gamma ray value or a resistivity value. The navigation advice considers defining a reference FE value (such as 30 API GR value), then monitoring a log (Gamma ray log, for example), and adjusting the well path towards meeting the Gamma ray value.

FIG. 7 depicts a wireframe of an interface 700 for automated reservoir navigation according to one or more embodiments described herein. The interface 700 includes an offset display portion 710 that shows the determined/calculated offset 711 and the offset threshold 712. The interface 700 further includes a relative dip display portion 720 that shows the determined/calculated relative dip 721 and the relative dip threshold 722. The interface 700 further includes a drainage area display portion 730 that shows the determined/calculated drainage area 731 and the drainage area threshold 732. The interface 700 also includes controls (e.g., control mechanisms) for controlling the offset (control 713), the relative dip (control 723), and the drainage area (control 733). The controls 713, 723, 733 are controllable by a user to adjust the respective offset threshold 712, the relative dip threshold 722, and the drainage area threshold 732. The interface also includes a well path display portion 740 that provides a schematic illustration of the BHA 13, the well path (601, 601a, 603) or a planned well path, the reference (602), and the metrics (e.g., offset, relative dip, drainage area). The display portion 740 can display, for example, one or more of FIGS. 6A-6F or other suitable schematics.

FIGS. 8A and 8B depict a target line triggering approach 800 according to one or more embodiments described herein. In this example, a target line is shown that is continuously updated for new measurement points (e.g., at each point in time in which a measurement is taken by the measurement tools 11). The target line may be defined and updated based on a location of a reference, such as reference 602 in FIGS. 6A-6F. For example, the target line may be defined and updated to be at a fixed distance to a reference or even parallel to a reference, such as reference 602. Triggers are implemented to indicate when to make navigational corrections. For example, triggers are computed by comparing the well path with a latest target line. The target line is a line that the well trajectory is supposed to approach and then follow. It may be defined with reference to the reservoir architecture (e.g., oil-water contact), such as by a predefined offset from or a desired distance to the reference (e.g., determined relative to total vertical depth). Triggers are used to initiate causing the BHA to navigate (see, e.g., blocks 510, 512 of FIG. 5).

FIG. 8A shows the example target line trigger approach 800 occurring at a first time (i.e., t₁), and FIG. 8B shows the approach 800 at a second time (i.e., t₂).

As shown in FIG. 8A, the approach 800 includes a current well path 801 having proceeded from a last survey point 802. The BHA 13 follows along the current well path 801 (including well path prediction as described with respect to FIGS. 6A-6F), and a measurement point for the BHA 13 (such as a sensor location as described herein) is disposed at point d₁ 803 along the well path 801 at the first time (i.e., t₁). It should be appreciated that the point d₁ 803 represents a distance along the well path 801 from a predefined reference point on well path 801 (e.g., the surface 3, the last survey point 802, or any other suitable reference point on well path 801).

The BHA 13 is being steered relative to an active target line 804 established relative to an active target point 805. The active target line 804 has a slope and an inclination that are related to each other and passes through the active target point 805. The BHA 13 is being navigated to meet the active target line 804 as shown to define an active well plan (or planned well path) 806. Well plan 806 may be defined by taking the steering capability into account. For example, if the buildup rate of BHA 13 is limited by a maximum buildup rate (e.g., 10°/100 ft), the curvature of well plan 806 may be limited to that maximum buildup rate. The point 807 represents the point where the active target line 804 is expected to meet the active well plan 806. This is referred to as a transition point to the planned tangent. The point 807 is an anticipation length 808 away from the point d₁ 803 (e.g., along the active well plan/planned well path 806).

At a next measurement time (e.g., at the second time (i.e., t₂)), a next measurement is taken (e.g., by the measurement tools 11 in BHA 13). That is, with reference to FIG. 3, the data acquisition system 320 receives real-time data from the BHA 13 and passes it to the navigation engine 312 (such as via the reservoir mapping engine 310 as shown). For example, at the second time (i.e., t₂), a second measurement of the distance from BHA 13 to reference (such as reference 602 in FIGS. 6A-6F, not shown in FIGS. 8A, 8B) may be taken and may be used to determine a new inclination of the reference, a new relative dip between well path 801/well plan 806 and reference, and/or a new drainage area. As can be seen in FIG. 8B, the BHA 13 has progressed to a point d₂ 810.

As shown, at the second time t₂, the active target line 804 of the first time t₁ and the active target point 805 of the first time t₁ are a previous target line 804 and a previous target point 805, respectively, and have been replaced by a new active target line 814 and a new active target point 815. The definition of new target line 814 and/or new target point 815 may be based on one or more of the determination of the new inclination of the reference, the new relative dip between well path 801/well plan 806 and reference, and/or the new drainage area. The BHA 13 (e.g., a sensor location on BHA 13) is, in FIG. 8B, a new anticipation length 818 away from the new transition point 817 (i.e., the transition point to the planned tangent).

Re-planning or navigating (e.g., sending a navigational command to the BHA 13 to cause the BHA 13 to navigate) can be based on one or more of the offset, the relative dip, and/or the drainage area. The relative dip may be defined with respect to the reference (such as reference 602 in FIGS. 6A-6F) or with respect to the target lines (804, 814). That is, the relative dip may be defined as the difference between inclinations of well path 601, 601a, 603, or planned well path and the reference 602 or may be defined as the difference between inclinations of well path 801 or planned well path 802 and target line 804. For example, if the relative dip 821 at the new anticipation length 818 is greater than the relative dip threshold, the BHA 13 may be caused to navigate differently (e.g., to correct the relative dip). As another example, if the offset (e.g., the delta TVD 820) at the new anticipation length 818 is greater than the offset threshold, the BHA 13 may be caused to navigate differently (e.g., to correct the offset). The drainage area can be used, in another example, to cause the BHA 13 to navigate differently, such as if the drainage area exceeds the drainage area threshold. It should be appreciated that other trigger events can be used to initiate or trigger navigation instructions/commands being downlinked to the BHA 13.

Example embodiments of the disclosure include or yield various technical features, technical effects, and/or improvements to technology. Example embodiments of the disclosure provide technical solutions for automated reservoir navigation. These technical solutions collect and analyze large volumes of data collected in wellbore by a measurement device disposed in a bottom hole assembly, then evaluate the data to determine when to cause the BHA to navigate based on the collected data. The large volume of data, complexity of the performing evaluation(s), and the real-time or near-real-time nature of adjusting the trajectory of the bottom hole assembly cannot practically be performed in the human mind. Moreover, by controlling the BHA using the collected data and comparing to thresholds for determining when to make navigation determinations, one or more embodiments described herein improve the operation of the BHA and the drilling of the wellbore by reducing the frequency of advice so as to not overly trigger navigation advice, which could cause mistrust by users and create poor wellbores. Thus, the techniques described herein represent an improvement to geosteering technologies. Accordingly, drilling decisions can be made more accurately and faster, thus improving drilling efficiency, reducing non-production time, improving hydrocarbon recovery, and the like. Specifically, geosteering is improved by acquiring and maintaining a desired position of the BHA relative to a reference. This increases hydrocarbon recovery from a hydrocarbon reservoir compared to conventional techniques.

Set forth below are some embodiments of the foregoing disclosure:

Embodiment 1: A method for automated reservoir navigation is disclosed. The method includes receiving a reference indicative of a reservoir architecture; determining a first distance between a well path and the reference and a second distance between the well path and the reference; determining a discrepancy based on the first distance and the second distance; and causing a bottom hole assembly to navigate based at least in part on the discrepancy.

Embodiment 2: A method according to any prior embodiment, wherein the discrepancy is indicative of at least one of an offset between the well path and the reference, a relative dip between the well path and the reference, or a drainage area between the well path and the reference.

Embodiment 3: A method according to any prior embodiment, wherein the well path is based on extrapolated points.

Embodiment 4: A method according to any prior embodiment, wherein the reference is based at least in part on at least one of data selected from the group consisting of lithology data, acoustic data, rheological data, electromagnetic data, and resistivity data.

Embodiment 5: A method according to any prior embodiment, wherein the offset is determined relative to a measurement point of the bottom hole assembly, at a drill bit of the bottom hole assembly, or a defined distance ahead of the drill bit.

Embodiment 6: A method according to any prior embodiment, wherein determining the offset relative to the defined distance ahead of the drill bit is based at least in part on an extrapolation technique.

Embodiment 7: A method according to any prior embodiment, wherein the relative dip is determined from an orientation, a direction, or a slope of the well path and the reference over an interval of the well path.

Embodiment 8: A method according to any prior embodiment, wherein the drainage area is determined by summing a plurality of drainage area portions over an interval of the well path wherein the drainage portions are calculated by multiplying a distance between the well path and the reference with a distance along the well path.

Embodiment 9: A method according to any prior embodiment, wherein the interval is set based on how undulating or constant the reference is.

Embodiment 10: A method according to any prior embodiment, further comprising providing an interface, wherein the interface presents the offset, the relative dip, and the drainage area and a control mechanism to enable controlling the bottom hole assembly.

Embodiment 11: A system for automated reservoir navigation is disclosed. The system includes a bottom hole assembly disposed in a wellbore; and a processing system for executing computer readable instructions, the computer readable instructions controlling the processing system to perform operations including: receiving a reference indicative of a reservoir architecture; determining at least one of a relative dip between the well path and the reference and a drainage area between the well path and the reference; and causing the bottom hole assembly to navigate based at least in part on at least one of the relative dip, or the drainage area.

Embodiment 12: A system according to any prior embodiment, wherein the well path is based on extrapolated points.

Embodiment 13: A system according to any prior embodiment, wherein the reference is based at least in part on at least one of data selected from the group consisting of lithology data, acoustic data, rheological data, and resistivity data.

Embodiment 14: A system according to any prior embodiment, wherein the offset is determined relative to a measurement point of the bottom hole assembly, at a drill bit of the bottom hole assembly, or a defined distance ahead of the drill bit.

Embodiment 15: A system according to any prior embodiment, wherein determining the offset relative to the defined distance ahead of the drill bit is based at least in part on an extrapolation technique.

Embodiment 16: A system according to any prior embodiment, wherein the relative dip is determined from an orientation, a direction, or a slope of the well path and the reference over an interval.

Embodiment 17: A system according to any prior embodiment, wherein the drainage area is determined by summing a plurality of drainage area portions over an interval of the well path wherein the drainage portions are calculated by multiplying a distance between the well path and the reference with a distance along the well path.

Embodiment 18: A system according to any prior embodiment, wherein the interval is set based on how undulating or constant the reference is.

Embodiment 19: A system according to any prior embodiment, wherein the operations further include providing an interface, wherein the interface presents at least one of the relative dip, and the drainage area and a control mechanism to enable controlling the bottom hole assembly.

Embodiment 20: A system according to any prior embodiment, wherein the processing system comprises a controller that controls the relative dip or the drainage area.

The use of the terms “a” and “an” and “the” and similar referents in the context of describing the present disclosure (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).

The teachings of the present disclosure can be used in a variety of well operations. These operations can involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents can be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

While the present disclosure has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes can be made and equivalents can be substituted for elements thereof without departing from the scope of the present disclosure. In addition, many modifications can be made to adapt a particular situation or material to the teachings of the present disclosure without departing from the essential scope thereof. Therefore, it is intended that the present disclosure not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this present disclosure, but that the present disclosure will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the present disclosure and, although specific terms can have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the present disclosure therefore not being so limited.

Claims

1. A method for automated reservoir navigation, the method comprising:

receiving a reference indicative of a reservoir architecture;

determining a first distance between a well path and the reference and a second distance between the well path and the reference;

determining a discrepancy based on the first distance and the second distance; and

causing a bottom hole assembly to navigate based at least in part on the discrepancy.

2. The method of claim 1, wherein the discrepancy is indicative of at least one of an offset between the well path and the reference, a relative dip between the well path and the reference, or a drainage area between the well path and the reference.

3. The method of claim 1, wherein the well path is based on extrapolated points.

4. The method of claim 1, wherein the reference is based at least in part on at least one of data selected from the group consisting of lithology data, acoustic data, rheological data, electromagnetic data, and resistivity data.

5. The method of claim 1, wherein the offset is determined relative to a measurement point of the bottom hole assembly, at a drill bit of the bottom hole assembly, or a defined distance ahead of the drill bit.

6. The method of claim 5, wherein determining the offset relative to the defined distance ahead of the drill bit is based at least in part on an extrapolation technique.

7. The method of claim 1, wherein the relative dip is determined from an orientation, a direction, or a slope of the well path and the reference over an interval of the well path.

8. The method of claim 1, wherein the drainage area is determined by summing a plurality of drainage area portions over an interval of the well path wherein the drainage portions are calculated by multiplying a distance between the well path and the reference with a distance along the well path.

9. The method of claim 8, wherein the interval is set based on how undulating or constant the reference is.

10. The method of claim 1, further comprising providing an interface, wherein the interface presents the offset, the relative dip, and the drainage area and a control mechanism to enable controlling the bottom hole assembly.

11. A system for automated reservoir navigation, the system comprising:

a bottom hole assembly disposed in a wellbore; and

a processing system for executing computer readable instructions, the computer readable instructions controlling the processing system to perform operations comprising: receiving a reference indicative of a reservoir architecture; determining at least one of a relative dip between the well path and the reference and a drainage area between the well path and the reference; and causing the bottom hole assembly to navigate based at least in part on at least one of the relative dip, or the drainage area.

12. The system of claim 11, wherein the well path is based on extrapolated points.

13. The system of claim 11, wherein the reference is based at least in part on at least one of data selected from the group consisting of lithology data, acoustic data, rheological data, and resistivity data.

14. The system of claim 11, wherein the offset is determined relative to a measurement point of the bottom hole assembly, at a drill bit of the bottom hole assembly, or a defined distance ahead of the drill bit.

15. The system of claim 14, wherein determining the offset relative to the defined distance ahead of the drill bit is based at least in part on an extrapolation technique.

16. The system of claim 11, wherein the relative dip is determined from an orientation, a direction, or a slope of the well path and the reference over an interval.

17. The system of claim 11, wherein the drainage area is determined by summing a plurality of drainage area portions over an interval of the well path wherein the drainage portions are calculated by multiplying a distance between the well path and the reference with a distance along the well path.

18. The system of claim 17, wherein the interval is set based on how undulating or constant the reference is.

19. The system of claim 11, wherein the operations further comprise providing an interface, wherein the interface presents at least one of the relative dip, and the drainage area and a control mechanism to enable controlling the bottom hole assembly.

20. The system of claim 11, wherein the processing system comprises a controller that controls the relative dip or the drainage area.