GEOSTEERING SYSTEM

BACKGROUND

Currently, one or more operators run a geosteering application when drilling a path within a wellbore. Once new target(s) are determined, the operator manually communicates the new targets to a directional driller. Once communicated, the directional driller would perform manual forward projection on a directional well path planning software system to achieve a target well path, and manually determine the optimum steering commands to be manually downlinked to a rotary steerable system tool. This can be a tedious and time consuming process and involves many manual steps. Communications are usually conducted through phone or email between each link, and the time taken for each decision to be conveyed and executed may be up to 20-30 minutes. Anti-Collision risks require manual scans which can be prone to errors. The scans are done by a different person than the one who is creating targets which can lead to communication errors. What is needed is a geosteering system which can update a well path and communicate the updated well path to drilling controls within the wellbore in a shorter amount of time and less prone to errors than the previous manual communication.

BRIEF DESCRIPTION OF THE DRAWINGS

Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:

FIG. 1 depicts an example system that includes directional drilling, according to some embodiments;

FIG. 2 depicts an example geosteering system having a geosteering application and a drilling application communicatively coupled together, according to some embodiments;

FIG. 3 depicts an example method for geosteering control of drilling a wellbore, according to some embodiments;

FIGS. 4A-4B illustrate wellbore orientation graphs, according to some embodiments;

FIGS. 5A-5B illustrate wellbore orientation graphs showing an updated well path determined by a geosteering application in contrast with an initial well path, according to some embodiments;

FIGS. 6A-6B illustrate wellbore orientation graphs showing an updated well path, according to some embodiments; and

FIG. 7 illustrates an example computer which may be used with a geosteering system, according to some embodiments.

DETAILED DESCRIPTION

The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details.

Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to a direct interaction between the elements and may also include an indirect interaction between the elements described. Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” or other like terms shall be construed as generally toward the bottom, terminal end of the well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. In some instances, a part near the end of the well can be horizontal or even slightly directed upwards. Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

Embodiments of the disclosure include systems and methods for automatically linking geosteering outputs which from a real-time geosteering application to drilling automation control parameters, such as may be implemented on an autonomous drilling application. In some embodiments, the geosteering application and the drilling application may be communicatively coupled via one or more software interfaces, in some embodiments, via an application programming interface (API). The geosteering application may determine a geologic target or trajectory in a subsurface formation. The geologic target may be a well path or may be a zone within a subsurface formation that includes minerals or hydrocarbons therein. In some embodiments, the geosteering application may determine an initial well path or trajectory and transmit the well path to the drilling application for controlling drilling equipment within the wellbore. The geosteering application may receive drilling data from the drilling application and determine whether the well path needs to be updated for one or more new targets. Once one or more new target(s) is determined based on the drilling data received from the drilling application, the geosteering application translates a new target trajectory/updated well path. The new target trajectory/updated well path may be sent digitally to the drilling application which provides recommended sequences of drilling system controllable parameters (such as tool face TF, duty-cycle, deflections, Inclination and Azimuth target cruise control set points and various other parameters). The drilling application may also produce a projected well path based on the recommended parameters. The sequences may then be executed automatically through digitally controlled downlink telemetry devices to drilling tools positioned within the wellbore. In some embodiments the drilling tools may comprise a rotary steerable system (RSS). The drilling application may also compute real-time tool performance parameters and measurements (such as tool yield, projected drilling path, bit projection, anti-collision scans, and real time depth) and projected drilling path based on models and digitally send the computed information and parameters back to the geosteering application. The information may then be used by the geosteering application to fine tune future target determinations and update the well path.

One of the inputs factored into determining the geologic target trajectory/well path is a dog leg severity (DLS) max parameter, which may be based on a customer requirement. The DLS max may be dynamically transferred from the drilling application to the geosteering application. The geosteering application may then be able to perform a quality control (QC) check of the proposed updated target trajectory/well path. In some embodiments, the QC check may be performed by a geosteering engineer, and in some embodiments, may be implemented on a computer. Additional inputs that may be factored into updating the target trajectory/well path and the QC check of the well path may include Anti-Collision scan, real-time tool performance, and real-time depth of the drilling tools and will provide instant feedback of the new well path feasibility to the geosteering application. This will reduce QC time and it will remove human driven errors.

Example Well System

FIG. 1 depicts an example system that includes directional drilling, according to some embodiments. FIG. 1 depicts a system 100. The system 100 will be specifically described below such that the system is used to direct a drill bit in drilling a wellbore, such as a subsea well or a land well. Example embodiments are not limited to only drilling an oil well. Some implementations may also encompass natural gas wellbores, other hydrocarbon wellbores, or wellbores in general. Further, some implementations may be used for the exploration and formation of geothermal wellbores intended to provide a source of heat energy instead of hydrocarbons.

Accordingly, FIG. 1 shows a tool string 126 disposed in a directional borehole 116. The tool string 126 includes a rotary steerable tool 128. The rotary steerable tool 128 may provide a full three dimensional directional control of a drill bit 114. A drilling platform 102 supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108. A kelly 110 supports the drill string 108 as the drill string 108 is lowered through a rotary table 112. In some implementations, a topdrive may be used to rotate the drill string 108 in place of the kelly 110 and the rotary table 112. The drill bit 114 is positioned at the downhole end of the tool string 126. In some implementations, the tool string 126 may be driven by a downhole motor 129 positioned on the tool string 126 and/or by rotation of the entire drill string 108 from the surface. As the drill bit 114 rotates, the drill bit 114 creates the borehole 116 that passes through various formations 118. A pump 120 may circulate drilling fluid through a feed pipe 122 and downhole through the interior of drill string 108, through orifices in the drill bit 114, back to the surface via the annulus 136 around the drill string 108, and into a retention pit 124. The drilling fluid transports cuttings from the borehole 116 into the pit 124 and aids in maintaining the integrity of the borehole 116. The drilling fluid may also drive the downhole motor 129.

The tool string 126 may include one or more logging while drilling (LWD) or measurement-while-drilling (MWD) tools 132 that collect data and measurements relating to various borehole and formation properties as well as the position of the drill bit 114 and various other drilling conditions as the drill bit 114 extends the borehole 108 through the formations 118. The LWD/MWD tool 132 may include a device for measuring formation resistivity, a gamma ray device for measuring formation gamma ray intensity, devices for measuring the inclination and azimuth of the tool string 126, pressure sensors for measuring drilling fluid pressure, temperature sensors for measuring borehole temperature, etc.

The tool string 126 may also include a telemetry module 134. In some embodiments, the telemetry module 134 may include or be coupled with an autonomous drilling application. The telemetry module 134 may receive data provided by the various sensors of the tool string 126 (e.g., sensors of the LWD/MWD tool 132) and drilling information from the RSS drilling tool 128 and may transmit the data to a surface control unit 138. In some embodiments, the surface unit 138 may include a geosteering application coupled therewith. The geosteering application and surface control unit 138 may be communicatively coupled with the drilling application and the telemetry module 134. Data sent from the geosteering application to the drilling application may then be transmitted to the tools (e.g., a downhole measuring tools such as LWD/MWD tool 132, a rotary steering system (RSS) drilling tool 128, etc.) of the tool string 126. In some implementations, an application programming interface (API), mud pulse telemetry, wired drill pipe, acoustic telemetry, or other telemetry technologies may be used to provide communication between the surface control unit 138 and the telemetry module 134. In some implementations, the geosteering application may communicate directly with the drilling application via an API for communication with and control of the LWD/MWD tool 132 and/or the RSS 128. The surface control unit 138 may be a computer stationed at the well site, a portable electronic device, a remote computer, or distributed between multiple locations and devices. The surface control unit 138 may also be a control unit that controls functions of the equipment of the tool string 126.

The RSS 128 is configured to change the direction of the tool string 126 and/or the drill bit 114, such as based on information indicative of tool 128 orientation and a desired drilling direction received from the drilling application. In one or more embodiments, the RSS 128 is coupled to the drill bit 114 and may drive rotation of the drill bit 114. Specifically, the RSS 128 may rotate in tandem with the drill bit 114. In some implementations, the rotary steerable tool 128 may be a point-the-bit system or a push-the-bit system.

Example Geosteering System

FIG. 2 illustrates a geosteering system 200 according to embodiments of the disclosure. The system 200 includes a geosteering application 205 communicatively coupled with a drilling application 210. The geosteering application 205 may be a real-time geosteering application and be implemented on a non-transitory computing system. The drilling application 210 may be an autonomous drilling application and may also, in some embodiments be implemented as part of a non-transitory computing system. The system 200 provides a two-way communication system 220 wherein the geosteering application 205 and the drilling application 210 are communicatively coupled by a programming interface such as an application programming interface (API). In some embodiments, the geosteering application 205 and drilling application may be physically located in two different locations and may communicate via an ethernet connection.

Embodiments of the geosteering system 200 and methods descried herein enable fully automated control of drilling equipment when geosteering. Additional benefits of the geosteering system 200 include a reduction in personnel needs and risks of mistakes during communications between all aspects of drilling system. A two-way communication system 220 of data between the geosteering application 205 and drilling application 210 may help reduce the time between decision making regarding an updated well path and execution within the wellbore from at least 20-30 minutes down to as low as about 2-5 minutes. Further an automated quality control (QC) of targets and the updated well path projection removes any human error factors and is a lot more robust.

In some example systems, the geosteering application 205 may be a computer implemented application such as the “RoxC” real-time geosteering application. The drilling application 210 may be a computer implemented application such as the “LOGIX” autonomous drilling application.

Data may be communicated between the geosteering application 205 and the drilling application 210 via the two-way communication system 220 may include targets, a well path, updates to the well path, and drilling data. The drilling data may include tool performance and parameters, including RSS tool performance information and well path projections. Additional drilling data and information communicated will be discussed herein in more detail.

Example Method

FIG. 3 illustrates an example method 300 for applying the geosteering system 200 to a wellbore drilling operation. The method 300 is described for determining and updating a well path, but could be applied for determining a target trajectory for one or more geologic targets. The method begins in a block 305.

In a block 310, a geosteering application (e.g. geosteering application 205) determines an initial well path for the wellbore based on modelling data and projections from surveys and data collected during planning for the wellbore.

In a block 315, the geosteering application transmits, via an application programming interface (API), the initial well path to a drilling application (e.g. drilling application 210) which is communicatively coupled with drilling equipment positioned downhole. The drilling equipment, in some embodiments, may include a rotary steerable system (RSS) drilling tool and at least one drill bit.

In a block 320, the drilling application provides recommended sequences of drilling parameters for controlling drilling equipment to implement the well path. The parameters may include TF, duty-cycle, deflections, Inclination and Azimuth target cruise control set points and various other parameters. The drilling application may also produce a projected well path based on the recommended parameters. The drilling application may be coupled with the drilling equipment via digitally controlled telemetry devices such that the drilling application can autonomously and digitally control the drilling equipment downhole.

In a block 325, the drilling application collects drilling data from drilling equipment and downhole measuring tools. In some embodiments, the drilling data may include LWD/MWD measurements, measurements computed by the drilling application, measurements and data collected by sensors which may be positioned within the wellbore and coupled with the drilling application, real-time drilling parameters and tool performance of the drilling equipment, real-time depth of the drilling apparatus, anticollision scans, and various other drilling data and measurements that may be collected during drilling of a wellbore. The anti-collision scans may include at least one of a real-time survey of possible collisions within the well path, a straight-line projection of the well path, and an extended projection of pinpoint collision zones along the well path. In some embodiments, the anti-collision scans are performed and computed by software stored on a processor implemented with or coupled with the drilling application. The drilling data may also include pre-set parameters input prior to drilling, such as DLS Max, operator key performance indicator (KPI) limits, limitation due to completions equipment/pumps and other pre-set limits and parameters used for drilling in the wellbore.

In a block 330, the geosteering application may receive, via the API, the drilling data from the drilling application.

In a block 335, the geosteering application reviews and processes the drilling data and updates the well path based on the drilling data.

In a block 340, there may be an engineering review of the drilling the updated well path as determined in block 335. In some embodiments, this may be performed by a geosteering engineer and in other embodiments, this may be performed by a processor. After reviewing the data, the updated well path may be adjusted and updated further.

In a block 345, the updated well path is transmitted, via the API, to the drilling application. In a block 350, the drilling application may adjust the drilling parameters based on the updated well path and communicate the updated well path and drilling parameters to the drilling equipment for controlling the drilling equipment downhole. In some embodiments, the drilling application may model or further update the updated well path based on recommended control parameters and projections and control the drilling equipment based on modeled or further updated well path.

In a block 355, if the wellbore drilling is not complete, the method cycles back to blocks 325 through 350 until the drilling is complete. When the drilling of the wellbore is complete, the method ends at block 360.

The flowchart is provided to aid in understanding the illustrations and are not to be used to limit scope of the claims. The flowchart depicts example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. For example, the operations depicted in blocks 325 to blocks 355 may be performed in parallel or concurrently. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, may be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus.

Example Graphs

Referring now to FIGS. 4A-4B, there are shown wellbore orientation graphs showing an initial well plan and drilling trajectory as planned or measured by a directional survey of the formation. Graph 400A represents an inclination plot, wherein the x-axis represents measured depth in meters (m) and the y-axis represents an inclination/vertical angle in degrees measured from the down direction. The down, horizontal and up directions have inclinations of 0°, 90° and 180°, respectively. Graph 400B represents an azimuth plot of the wellbore. The x-axis represents measured depth in meters (m) and the y-axis represents an azimuth of the wellbore in degrees with respect to the geographic or magnetic north path. The north, east, south and west directions have azimuths of 0°, 90°, 180° and 270°, respectively. In each of the graphs, plotline 405 represents definitive measured surveys taken of the formation during well drilling. Plotline 410 represents an initial well path determined by a geosteering application, such as geosteering application 205. The original well path represented by plotline 410 may be created based on a well planning application. Plotline 415 represents a first projected well path. The projected well path represented by plotline 415 may be produced by the drilling application based on recommendation from the drilling application and original well plan. While the measured depth is shown in FIGS. 4A-4B, 5A-5B, and 6A-6B in meters, the measured depth may be represented by other units, such as feet, etc.

Referring now to FIGS. 5A-5B, there are shown wellbore orientation graphs showing a contrast between initial well path projections and an updated well path determined by a geosteering application. Graph 500A represents an inclination plot, wherein the x-axis represents measured depth in meters (m) and the y-axis represents an inclination of the well path in degrees measured from the down direction. Graph 500B represents an azimuth plot wherein the x-axis represents measured depth in meters (m) and the y-axis represents an azimuth of the well path in degrees with respect to the geographic or magnetic north path. In each of the graphs, plotline 505 represents definitive measured surveys taken of the formation during well drilling. Plotline 510 represents an initial well path determined by a geosteering application. The original well path represented by plotline 510 may be created based on a well planning application. Plotline 515 represents a first projection based on data from a drilling application. The projected well path represented by plotline 515 may be produced by the drilling application based on recommendation from the drilling application and original well plan. Plotline 520 represents an updated well path created by the geosteering after receiving drilling data received from the drilling application. As shown in FIGS. 5A-5B, the updated well path will likely vary from the initial well path. Embodiments of the geosteering system according to the disclosure may reduce the communication and control of the drilling equipment to adjust to the new well path, in some examples, reduced from 20-30 minutes down to as little as 2-5 minutes. As a result, the controls to the drilling equipment for implementation of the updated well path may provide a more accurate and productive well path according to actual drilling parameters and drilling than previously possible when manual review and entry into a geosteering model were required for adjustment of the well path.

Referring now to FIGS. 6A-6B, there is shown wellbore orientation graphs representing an updated well path determined by a geosteering application after receiving drilling data from a drilling application. Graph 600A represents an inclination plot, wherein the x-axis represents measured depth in meters (m) and the y-axis represents an inclination of the well path in degrees measured from the down direction. Graph 600B represents an azimuth plot wherein the x-axis represents measured depth in meters (m) and the y-axis represents an azimuth of the well path in degrees with respect to the geographic or magnetic north path. In each of the graphs, plotline 605 represents definitive measured surveys taken of the formation during well drilling. Plotline 610 represents an updated well path determined by the geosteering application and transmitted to the drilling application for controlling the drilling equipment downhole. The updated well path represented by plotline 610 is based on drilling data received from the drilling application.

As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.

Any combination of one or more machine-readable medium(s) may be utilized. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.

A machine-readable signal medium may include a propagated data signal with machine-readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.

Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.

Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine.

The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.

Example Computer

FIG. 7 depicts an example computer, according to some embodiments. A computer 700 includes a processor 705 (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer 700 includes a memory 710. The memory 710 may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer 700 also includes a bus 715 and a network interface 720. The computer 700 communicates via transmissions to and/or from remote devices via the network interface 720 in accordance with a network protocol corresponding to the type of network interface, whether wired or wireless and depending upon the carrying medium. In addition, a communication or transmission can involve other layers of a communication protocol and or communication protocol suites (e.g., transmission control protocol, Internet Protocol, user datagram protocol, application programming interfaces, virtual private network protocols, etc.). The system also includes a geosteering application 725 and a drilling application 730 communicatively coupled together via a two-way communication system. The drilling application 730 may be coupled with drilling equipment positioned in the wellbore, in some embodiments, RSS drilling tools. The geosteering application 725 and drilling application 730 exchange data to control drilling equipment downhole to follow an initial well path and then updating the well path and communicating the updated well path for the drilling equipment to follow a different trajectory.

The computer 700 also includes a signal processor 735 and a controller 740. The signal processor 735 and the controller 740 can perform one or more of the operations described herein. For example, the signal processor 735 may process the signals at or between the geosteering application, drilling application, and drilling equipment (as described herein). The controller 740 may perform various control operations to a wellbore operation (such as transmitting signals between various features of the geosteering system (as described herein).

Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 705. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 705, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in FIG. 7 (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor 705 and the network interface 720 are coupled to the bus 715. Although illustrated as being coupled to the bus 715, the memory 705 may be coupled to the processor 735 and/or controller 740.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for geosteering and drilling as described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.

Example Embodiments

Aspects disclosed herein include:

Aspect A: A method, comprising: determining a geologic target for a wellbore; transmitting, via an application programming interface (API), the geologic target to a drilling application for controlling drilling equipment in the wellbore; receiving, via the API, drilling data from the drilling application; updating the geologic target based on the drilling data; and transmitting, via the API, the updated geologic target to the drilling application for controlling equipment in the wellbore.

Aspect B: A non-transitory, machine-readable medium having instructions stored thereon that are executable by a processor, the instructions comprising: instructions to determine a geologic target for a wellbore; instructions to transmit, via an application programming interface (API), the geologic target to a drilling application for controlling drilling equipment in the wellbore; instructions to receive, via the API, drilling data from the drilling application; instructions to update the geologic target based on the drilling data; and instructions to transmit, via the API, the updated geologic target to the drilling application for controlling the drilling equipment in the wellbore.

Aspect C: A system, comprising: a drilling apparatus positioned downhole in a wellbore; a geosteering application communicatively coupled with the drilling apparatus, the geosteering application configured to: determine a geologic target; transmit, via an application programming interface (API), the geologic target to a drilling application for controlling the drilling apparatus in the wellbore; receive, via the API, drilling data from the drilling application; update the geologic target based on the drilling data; and transmit, via the API, the updated geologic target to the drilling application for controlling the drilling apparatus in the wellbore.

Aspects A, B, and C may have one or more of the following additional elements in combination:

Element 1: wherein the drilling data from the drilling application are computed measurements.

Element 2: wherein the drilling data include anti-collision scans from the drilling application.

Element 3: wherein the drilling data include real-time tool performance.

Element 4: wherein the drilling data include real-time depth of the geologic target.

Element 5: wherein the drilling data include logging while drilling measurements taken by a downhole measuring tool.

Element 6: further comprising receiving input from a geosteering engineer reviewing the drilling data and updating the geologic target based on input.

Element 7: wherein the geologic target is a well path.

Element 8: wherein the drilling application models the updated well path and recommends control parameters for controlling drilling equipment in the wellbore.

Element 9: wherein the drilling data include anti-collision scans from the drilling application, and the anti-collision scans include at least one of a real-time survey of possible collisions within the geologic target, a straight-line projection of the geologic target, and an extended projection of pinpoint collision zones along the geologic target.

Element 10: further comprising instructions to receive input from a geosteering engineer reviewing the drilling data and update the geologic target based on the input.

Element 11: wherein the geosteering application is further configured to receive anti-collision scans from the drilling application and update the geologic target based on the anti-collision scans.

Element 12: wherein the geosteering application is further configured to receive input from a geosteering engineer and update the geologic target.

Element 13: wherein the drilling apparatus includes drilling tools may comprise a rotary steerable system. coupled with at least one drill bit.

Element 14: wherein the drilling data include real-time depth of a drilling tool communicatively coupled with the drilling application.

Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments.

GEOSTEERING SYSTEM

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Abstract

Description

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