Systems, devices, and methods for generating an adjusted ideal drilling path

Systems, devices, and methods for visualizing and steering a drilling apparatus are provided, including a drill string with a bottom hole assembly (BHA), a sensor system, and a controller operable to generate a visualization comprising an original drill plan and an adjusted ideal drilling path. The adjusted ideal drilling path may represent an ideal drilling route based on updated drilling data received by the controller such as determined parameters of geological formations. The differences between the location of the BHA and the adjusted ideal drilling path may also be visualized. This visualization may be used by an operator or the controller to steer the BHA.

TECHNICAL FIELD

The present disclosure is directed to systems, devices, and methods for implementing steering in a drilling operation. In particular, the present disclosure includes presenting an ideal adjusted drilling path that may help an operator visualize and direct a drilling operation.

BACKGROUND OF THE DISCLOSURE

At the outset of a drilling operation, drillers typically establish a drill plan that includes a target location and a drilling path to the target location. Once drilling commences, the bottom hole assembly (BHA) may be directed or “steered” from a vertical drilling path in any number of directions, to follow the proposed drill plan. For example, to recover an underground hydrocarbon deposit, a drill plan might include a vertical bore to a side of a reservoir containing the deposit, then a directional or horizontal bore that penetrates the deposit. The operator may then follow the plan by steering the BHA through the vertical and horizontal aspects in accordance with the plan. Drill plans may be chosen to minimize the time required to drill a wellbore and/or to access the largest amounts of oil or gas possible.

Drilling operations in horizontal or near-horizontal wellbores pose additional challenges for drillers. For example, accessing a deposit may require that a driller drill multiple horizontal wellbores in close proximity. In this case, the tolerances for drilling each wellbore may be very small, and may require a high level of expertise as well as disciplined navigation to avoid making costly mistakes. Even minor inaccuracies in measurement or steering can cause problems for the current drilling operation as well as successive operations.

Furthermore, data received during a drilling operation may signal that changes are needed in the drill plan, such as to direct the BHA to a more productive area. These changes may be difficult for a driller to implement because they are not planned at the outset of the drilling operation and may present mathematical challenges to correctly maneuver the BHA according to the required changes.

Thus, a more efficient, reliable, and intuitive method for steering a BHA, visualizing drilling tolerances, and making changes in a drill plan is needed.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different implementations, or examples, for implementing different features of various implementations. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various implementations and/or configurations discussed.

The systems and methods disclosed herein display to a user a visualization of a representation of an actual drilling path and an adjusted ideal drilling path (e.g., a target path, also referred to as a GeoLine) that allows a user to conveniently compare the actual drill path to the adjusted ideal drilling path. The adjusted ideal drilling path may deviate from an original drill plan based on inputs or information determined from collected downhole data such as geological formation data. Some implementations also display to a user the original drill plan. Some implementations include intuitive visualizations of drilling windows which may be indicative of drilling tolerances along the adjusted ideal drilling path, as well as. These visualizations may help provide a more intuitive view of a down hole environment and correspond to more intuitive control of BHAs during a drilling procedure. These visualizations may be generated by utilizing data received from external sources such as geological surveys as well as from sensors associated with the drill systems and other input data.

Referring toFIG. 1, illustrated is a schematic view of an apparatus100demonstrating one or more aspects of the present disclosure. The apparatus100is or includes a land-based drilling rig. However, one or more aspects of the present disclosure are applicable or readily adaptable to any type of drilling rig, such as jack-up rigs, semisubmersibles, drill ships, coil tubing rigs, well service rigs adapted for drilling and/or re-entry operations, and casing drilling rigs, among others.

Apparatus100includes a mast105supporting lifting gear above a rig floor110. The lifting gear includes a crown block115and a traveling block120. The crown block115is coupled at or near the top of the mast105, and the traveling block120hangs from the crown block115by a drilling line125. One end of the drilling line125extends from the lifting gear to drawworks130, which is configured to reel in and out the drilling line125to cause the traveling block120to be lowered and raised relative to the rig floor110. The other end of the drilling line125, known as a dead line anchor, is anchored to a fixed position, possibly near the drawworks130or elsewhere on the rig.

A hook135is attached to the bottom of the traveling block120. A top drive140is suspended from the hook135. A quill145extending from the top drive140is attached to a saver sub150, which is attached to a drill string155suspended within a wellbore160. Alternatively, the quill145may be attached to the drill string155directly. The term “quill” as used herein is not limited to a component which directly extends from the top drive, or which is otherwise conventionally referred to as a quill. For example, within the scope of the present disclosure, the “quill” may additionally or alternatively include a main shaft, a drive shaft, an output shaft, and/or another component which transfers torque, position, and/or rotation from the top drive or other rotary driving element to the drill string, at least indirectly. Nonetheless, albeit merely for the sake of clarity and conciseness, these components may be collectively referred to herein as the “quill.”

The drill string155includes interconnected sections of drill pipe165, a bottom hole assembly (BHA)170, and a drill bit175. The BHA170may include stabilizers, drill collars, and/or measurement-while-drilling (MWD) or wireline conveyed instruments, among other components. For the purpose of slide drilling the drill string may include a down hole motor with a bent housing or other bend component, operable to create an off-center departure of the bit from the center line of the wellbore. The direction of this departure in a plane normal to the wellbore is referred to as the toolface angle or toolface. The drill bit175, which may also be referred to herein as a “tool,” or a “toolface,” may be connected to the bottom of the BHA170or otherwise attached to the drill string155. One or more pumps180may deliver drilling fluid to the drill string155through a hose or other conduit, which may be connected to the top drive140.

The down hole MWD or wireline conveyed instruments may be configured for the evaluation of physical properties such as pressure, temperature, gamma radiation count, torque, weight-on-bit (WOB), vibration, inclination, azimuth, toolface orientation in three-dimensional space, and/or other down hole parameters. These measurements may be made down hole, stored in memory, such as solid-state memory, for some period of time, and downloaded from the instrument(s) when at the surface and/or transmitted in real-time to the surface. Data transmission methods may include, for example, digitally encoding data and transmitting the encoded data to the surface, possibly as pressure pulses in the drilling fluid or mud system, acoustic transmission through the drill string155, electronic transmission through a wireline or wired pipe, transmission as electromagnetic pulses, among other methods. The MWD sensors or detectors and/or other portions of the BHA170may have the ability to store measurements for later retrieval via wireline and/or when the BHA170is tripped out of the wellbore160.

In an exemplary implementation, the apparatus100may also include a rotating blow-out preventer (BOP)158that may assist when the well160is being drilled utilizing under-balanced or managed-pressure drilling methods. The apparatus100may also include a surface casing annular pressure sensor159configured to detect the pressure in an annulus defined between, for example, the wellbore160(or casing therein) and the drill string155.

In the exemplary implementation depicted inFIG. 1, the top drive140is utilized to impart rotary motion to the drill string155. However, aspects of the present disclosure are also applicable or readily adaptable to implementations utilizing other drive systems, such as a power swivel, a rotary table, a coiled tubing unit, a down hole motor, and/or a conventional rotary rig, among others.

The apparatus100also includes a controller190configured to control or assist in the control of one or more components of the apparatus100. For example, the controller190may be configured to transmit operational control signals to the drawworks130, the top drive140, the BHA170and/or the pump180. The controller190may be a stand-alone component installed on the rig floor110near the mast105and/or near other components of the apparatus100. In an exemplary implementation, the controller190includes one or more systems located in a control room in communication with the apparatus100, such as the general purpose shelter often referred to as the “doghouse” serving as a combination tool shed, office, communications center, and general meeting place. The controller190may be configured to transmit the operational control signals to the drawworks130, the top drive140, the BHA170, and/or the pump180via wired or wireless transmission devices which, for the sake of clarity, are not depicted inFIG. 1.

The controller190is also configured to receive electronic signals via wired or wireless transmission devices (also not shown inFIG. 1) from a variety of sensors included in the apparatus100, where each sensor is configured to detect an operational characteristic or parameter. Depending on the implementation, the apparatus100may include a down hole annular pressure sensor170acoupled to or otherwise associated with the BHA170. The down hole annular pressure sensor170amay be configured to detect a pressure value or range in an annulus shaped region defined between the external surface of the BHA170and the internal diameter of the wellbore160, which may also be referred to as the casing pressure, down hole casing pressure, MWD casing pressure, or down hole annular pressure. Measurements from the down hole annular pressure sensor170amay include both static annular pressure (pumps off) and active annular pressure (pumps on).

It is noted that the meaning of the word “detecting,” in the context of the present disclosure, may include detecting, sensing, measuring, calculating, and/or otherwise obtaining data. Similarly, the meaning of the word “detect” in the context of the present disclosure may include detect, sense, measure, calculate, and/or otherwise obtain data.

The apparatus100may additionally or alternatively include a shock/vibration sensor170bthat is configured to detect shock and/or vibration in the BHA170. The apparatus100may additionally or alternatively include a mud motor pressure sensor172athat may be configured to detect a pressure differential value or range across one or more motors172of the BHA170. The one or more motors172may each be or include a positive displacement drilling motor that uses hydraulic power of the drilling fluid to drive the drill bit175, also known as a mud motor. One or more torque sensors172bmay also be included in the BHA170for sending data to the controller190that is indicative of the torque applied to the drill bit175by the one or more motors172.

The apparatus100may additionally or alternatively include a toolface sensor170cconfigured to detect the current toolface orientation. The toolface sensor170cmay be or include a conventional or future-developed magnetic toolface sensor which detects toolface orientation relative to magnetic north. Alternatively, or additionally, the toolface sensor170cmay be or include a conventional or future-developed gravity toolface sensor which detects toolface orientation relative to the Earth's gravitational field. The toolface sensor170cmay also, or alternatively, be or include a conventional or future-developed gyro sensor. The apparatus100may additionally or alternatively include a weight on bit (WOB) sensor170dintegral to the BHA170and configured to detect WOB at or near the BHA170.

The apparatus100may additionally or alternatively include a gamma sensor170econfigured to measure naturally occurring gamma radiation to characterize nearby rock and sediment. The gamma sensor170emay be disposed in or associated with the BHA170.

The apparatus100may additionally or alternatively include a torque sensor140acoupled to or otherwise associated with the top drive140. The torque sensor140amay alternatively be located in or associated with the BHA170. The torque sensor140amay be configured to detect a value or range of the torsion of the quill145and/or the drill string155(e.g., in response to operational forces acting on the drill string). The top drive140may additionally or alternatively include or otherwise be associated with a speed sensor140bconfigured to detect a value or range of the rotational speed of the quill145.

The top drive140, drawworks130, crown or traveling block, drilling line or dead line anchor may additionally or alternatively include or otherwise be associated with a WOB sensor140c(WOB calculated from a hook load sensor that can be based on active and static hook load) (e.g., one or more sensors installed somewhere in the load path mechanisms to detect and calculate WOB, which can vary from rig to rig) different from the WOB sensor170d. The WOB sensor140cmay be configured to detect a WOB value or range, where such detection may be performed at the top drive140, drawworks130, or other component of the apparatus100.

The detection performed by the sensors described herein may be performed once, continuously, periodically, and/or at random intervals. The detection may be manually triggered by an operator or other person accessing a human-machine interface (HMI), or automatically triggered by, for example, a triggering characteristic or parameter satisfying a predetermined condition e.g., expiration of a time period, drilling progress reaching a predetermined depth, drill bit usage reaching a predetermined amount, etc.). Such sensors and/or other detection devices may include one or more interfaces which may be local at the well/rig site or located at another, remote location with a network link to the system.

Referring toFIG. 2, illustrated is a block diagram of an apparatus200according to one or more aspects of the present disclosure. The apparatus200includes a user interface260, a bottom hole assembly (BHA)210, a drive system230, a drawworks240, and a controller252. The apparatus200may be implemented within the environment and/or apparatus shown inFIG. 1. For example, the BHA210may be substantially similar to the BHA170shown inFIG. 1, the drive system230may be substantially similar to the top drive140shown inFIG. 1, the drawworks240may be substantially similar to the drawworks130shown inFIG. 1, and the controller252may be substantially similar to the controller190shown inFIG. 1.

The user interface260and the controller252may be discrete components that are interconnected via wired or wireless devices. Alternatively, the user interface260and the controller252may be integral components of a single system or controller250, as indicated by the dashed lines inFIG. 2.

The user interface260may include data input device266for user input of one or more toolface set points, and may also include devices or methods for data input of other set points, limits, and other input data. The data input device266may include a keypad, voice-recognition apparatus, dial, button, switch, slide selector, toggle, joystick, mouse, data base and/or other conventional or future-developed data input device. Such data input device266may support data input from local and/or remote locations. Alternatively, or additionally, the data input device266may include devices for user-selection of predetermined toolface set point values or ranges, such as via one or more drop-down menus. The toolface set point data may also or alternatively be selected by the controller252via the execution of one or more database look-up procedures. In general, the data input device266and/or other components within the scope of the present disclosure support operation and/or monitoring from stations on the rig site as well as one or more remote locations with a communications link to the system, network, local area network (LAN), wide area network (WAN), Internet, satellite-link, and/or radio, among other devices.

The user interface260may also include a survey input device268. The survey input device268may include information gathered from sensors regarding the orientation and location of the BHA210. In some implementations, information is automatically entered into the survey input device268and the user interface at regular intervals.

The user interface260may also include a display device261arranged to present a two-dimensional visualization262and a three-dimensional visualization264for visually presenting information to the user in textual, graphic, or video form. In some implementations, the display device261is a computer monitor, an LCD or LED display, table, touch screen, or other display device. In some implementations, the two-dimensional visualization262and the three-dimensional visualization264include one or more depictions. As used herein, a “depiction” is a two-dimensional or three-dimensional user-viewable representation of an object (such as a BHA) or other data (such as a drill plan). These depictions may be figurative, and may be accompanied by data in a textual format. As used herein, a “visualization” is a two-dimensional or three-dimensional user-viewable representation of one or more depictions. In some implementations, a visualization may include a control interface where users may enter data or instructions. For example, the two-dimensional visualization262may be utilized by the user to view sensor data and input the toolface set point data with the data input device266. The toolface set point data input device266may be integral to or otherwise communicably coupled with the two-dimensional visualization262. The two-dimensional visualization262may also be used to visualize a particular drilling window as compared with the location of the BHA or drilled wellbore. In other implementations, a visualization is a representation of an environment from the viewpoint of a simulated camera. This viewpoint may be zoomed in or out, moved, or rotated to view different aspects of one or more depictions. For example, the three-dimensional visualization264may show a down hole environment including depictions of the BHA, the drill plan, and one or more drilling windows. Furthermore, the down hole environment may include information from a control interface overlaid on depictions of the BHA and drill plan. The three-dimensional visualization264may incorporate information shown on the two-dimensional visualization262. In some cases, the three-dimensional visualization264includes a two-dimensional visualization262overlaid on a three-dimensional visualization of the down hole environment which may include a depiction of a drill plan. The two-dimensional visualization262and three-dimensional visualization264will be discussed in further detail with reference toFIG. 3.

Still with reference toFIG. 2, the BHA210may include an MWD casing pressure sensor212that is configured to detect an annular pressure value or range at or near the MWD portion of the BHA210, and that may be substantially similar to the down hole annular pressure sensor170ashown inFIG. 1. The casing pressure data detected via the MWD casing pressure sensor212may be sent via electronic signal to the controller252via wired or wireless transmission.

The BHA210may also include an MWD shock/vibration sensor214that is configured to detect shock and/or vibration in the MWD portion of the BHA210, and that may be substantially similar to the shock/vibration sensor170bshown inFIG. 1. The shock/vibration data detected via the MWD shock/vibration sensor214may be sent via electronic signal to the controller252via wired or wireless transmission.

The BHA210may also include a mud motor pressure sensor216that is configured to detect a pressure differential value or range across the mud motor of the BHA210, and that may be substantially similar to the mud motor pressure sensor172ashown inFIG. 1. The pressure differential data detected via the mud motor pressure sensor216may be sent via electronic signal to the controller252via wired or wireless transmission. The mud motor pressure may be alternatively or additionally calculated, detected, or otherwise determined at the surface, such as by calculating the difference between the surface standpipe pressure just off-bottom and pressure once the bit touches bottom and starts drilling and experiencing torque.

The BHA210may also include a magnetic toolface sensor218and a gravity toolface sensor220that are cooperatively configured to detect the current toolface, and that collectively may be substantially similar to the toolface sensor170cshown inFIG. 1. The magnetic toolface sensor218may be or include a conventional or future-developed magnetic toolface sensor which detects toolface orientation relative to magnetic north. The gravity toolface sensor220may be or include a conventional or future-developed gravity toolface sensor which detects toolface orientation relative to the Earth's gravitational field. In an exemplary implementation, the magnetic toolface sensor218may detect the current toolface when the end of the wellbore is less than about 7° from vertical, and the gravity toolface sensor220may detect the current toolface when the end of the wellbore is greater than about 7° from vertical. However, other toolface sensors may also be utilized within the scope of the present disclosure, including non-magnetic toolface sensors and non-gravitational inclination sensors. In any case, the toolface orientation detected via the one or more toolface sensors (e.g., magnetic toolface sensor218and/or gravity toolface sensor220) may be sent via electronic signal to the controller252via wired or wireless transmission.

The BHA210may also include a MWD torque sensor222that is configured to detect a value or range of values for torque applied to the bit by the motor(s) of the BHA210, and that may be substantially similar to the torque sensor172bshown inFIG. 1. The torque data detected via the MWD torque sensor222may be sent via electronic signal to the controller252via wired or wireless transmission.

The BHA210may also include a MWD WOB sensor224that is configured to detect a value or range of values for WOB at or near the BHA210, and that may be substantially similar to the WOB sensor170dshown inFIG. 1. The WOB data detected via the MWD WOB sensor224may be sent via electronic signal to the controller252via wired or wireless transmission.

The BHA210may also include a lithology sensor. The lithology sensor may be any type of sensor to determine the location and/or composition of geologic formations around a drilling operation. In some implementations, the lithology sensor is a gamma sensor226that is configured to assist an operator in gathering lithology data from the formations around the BHA. In some implementations, the gamma sensor226is configured to measure naturally occurring gamma radiation to characterize nearby rock and sediment, and may be substantially similar to the gamma sensor170eshown inFIG. 1. In some implementations, the gamma sensor226produces a simple gamma count of gamma rays incident on the gamma sensor226. In other implementations, the gamma sensor226is configured to measure a direction associated with a gamma count. This type of gamma sensor226may be referred to as an azimuthal gamma sensor and may be particularly useful in gathering lithology information for directional drilling applications. In some implementations, an azimuthal gamma sensor may produce a list of gamma counts taken at different times and positions, wherein each gamma count corresponds to an angular measurement of the gamma sensor226.

In some implementations, the gamma sensor226may be used in conjunction with the controller242to determine whether the geology around the wellbore is producing as much as expected. For example, a drill plan may include a production estimate based on the geology it passes through. The gamma count of the gamma sensor226may be used to check this estimate and determine whether the current geology is “hot” or “cold” compared to its production potential (i.e., producing more or less than expected, respectively). In some implementations, data received by the gamma sensor226may be used to improve the production of a well by being used to make changes in the drill plan during the drilling operation.

The drawworks240may include a controller242and/or other devices for controlling feed-out and/or feed-in of a drilling line (such as the drilling line125shown inFIG. 1). Such control may include rotational control of the drawworks (in v. out) to control the height or position of the hook, and may also include control of the rate the hook ascends or descends.

The drive system230may include a surface torque sensor232that is configured to detect a value or range of the reactive torsion of the quill or drill string, much the same as the torque sensor140ashown inFIG. 1. The drive system230also includes a quill position sensor234that is configured to detect a value or range of the rotational position of the quill, such as relative to true north or another stationary reference. The surface torsion and quill position data detected via the surface torque sensor232and the quill position sensor234, respectively, may be sent via electronic signal to the controller252via wired or wireless transmission. The drive system230also includes a controller236and/or other devices for controlling the rotational position, speed, and direction of the quill or other drill string component coupled to the drive system230(such as the quill145shown inFIG. 1).

The controller252may be configured to receive one or more of the above-described parameters from the user interface260, the BHA210, the drawworks240, and/or the drive system230, and utilize such parameters to continuously, periodically, or otherwise determine the current toolface orientation. The controller252may be further configured to generate a control signal, such as via intelligent adaptive control, and provide the control signal to the drive system230and/or the drawworks240to adjust and/or maintain the toolface orientation. For example, the controller252may provide one or more signals to the drive system230and/or the drawworks240to increase or decrease WOB and/or quill position, such as may be required to accurately “steer” the drilling operation.

FIG. 3is an exemplary representation of an HMI400configured to relay information about the toolface location and orientation to a user of the display device261ofFIG. 2. This display may be the three-dimensional visualization264ofFIG. 2. In the example ofFIG. 3, the HMI400includes three-dimensional depictions of a drill plan410, a drilling motor and BHA428, and a drilled wellbore414, as well as two-dimensional depictions. The HMI400may be used by an operator to gain an intuitive view of the BHA and drill plan. In some implementations, the HMI400shows a “camera view” of the down hole environment, or the view that a simulated camera would show if imaging aspects of the down hole environment. The depiction of the toolface angle at the BHA428appears as symbols406on the concentric circular grid402in the example ofFIG. 3. This depiction shows the last recorded or measured location of the toolface and may include information about its orientation. In some implementations, the concentric circular grid402represents the most recent position of the BHA428(for example, one position for every ring of the concentric circular grid402). In one implementation, data concerning the location and orientation of the BHA428are shown in index420. In the example ofFIG. 3, the index420indicates that the most recent depth of the drilling bit428was measured at 12546.19 feet, the inclination was 89.65°, and the azimuth was 355.51°. In some instances, the depiction of the BHA428is centered in the HMI400, as shown inFIG. 3. In other implementations, index420contains data about the location and orientation of the simulated camera whose view is depicted in HMI400.

In some implementations, the depiction of the drill plan410may appear as a long, cylindrical string extending through the down hole environment. The depiction of the drill plan410may be created in the three-dimensional display based on data of a desired drill plan entered or otherwise uploaded by the user. The drill plan and associated depiction of the drill plan410may be changed during a drilling operation for a number of reasons, such as to improve drilling production, to avoid unforeseen obstacles (such as problematic geology, areas of limited maneuverability, damaged equipment or equipment or materials left in the wellbore from previous operations, etc.), or based on newly received data from external sources. In some implementations, the changes or modifications to the drill plan may be represented with a “adjusted ideal drilling path” that may be used as a reference to steer the428. The depiction of the adjusted ideal drilling path510may be depicted as a second shape, such as a solid line in the example ofFIG. 4, a dotted line, or other type of line, or a long, cylindrical string, as well as other shapes, and may be colored with a different color than the depiction of the drill plan410for ease of understanding. The adjusted ideal drilling path may represent an ideal path for the BHA428to be steered along based on data detected during the drilling process, such as geological data, and regularly reflects deviations from the original drill plan.

A three-dimensional compass412shows the orientation of the present view of the HMI400, and is an indication of an x-y-z coordinate system. The depiction of the drilled wellbore414extends outward from the depiction of the BHA428. In some cases, the drilled wellbore414can depict the location of the drill string along with previous measurements of the location and orientation of the toolface.

One or more stations440may be depicted along the drilled wellbore414or drill plan410. These stations440may represent planned or actual locations for events during a drilling operation. For example, the stations440may represent the location of surveys taken during the drilling process. In some cases, these surveys are taken at regular intervals along the wellbore. Furthermore, real-time measurements are made ahead of the last standard survey, and can give the user feedback on the progress and effectiveness of a slide or rotation procedure. These measurements may be used to update aspects of the visualization such as the drilled wellbore414and concentric circular grid402, advisory segment404, symbols406, and indicator408. In other implementations, the stations440represent a position selected by a user. The stations440may represent sections of the drill plan410or drilled wellbore414corresponding to one or more drilling windows.

In the example ofFIG. 3, the concentric circular grid402, advisory segment404, symbols406, and indicator408are overlaid on the three-dimensional visualization. In the example ofFIG. 3, the concentric circular grid402, advisory segment404, symbols406, and indicator408are centered on the depiction of the BHA428. In some implementations, a vector arrow409is depicted to show a recommended steering path. In particular, the vector arrow409may be configured to direct the BHA428to the adjusted ideal drilling path510(as shown inFIG. 4), the original drill plan410, or one or more drilling windows502.

Still referring toFIG. 3, index430shows data from the most recent movement of the drilling bit and toolface. Index430may include a current drilling bit depth measurement, a slide score, suggested corrective actions to align the BHA with the drill plan, and advisory measurements. In some implementations, the HMI400may be used to provide feedback to a user relating to steering accuracy. The effectiveness of steering the actual toolface may be judged by a slide score.

Index432shows data from past movements of the toolface. In the example ofFIG. 3, index432includes data from the last most recent section of the toolface steering, or sliding. Index432may contain, similar data to that of index430. In some cases, indexes430and432allow the user to track the movement of the drilling motor as it is steered through the down hole environment.

HMI400also includes functions to adjust the three-dimensional view of the HMI400. In particular, functions422,424,426, and434allow a user to reorient the HMI400to view different aspects of the toolface or drill plan. In the example ofFIG. 3, the view of the HMI400is centered on the drilled wellbore414with the depiction of the BHA428at the center. Function422removes the view of the HMI400from the drilled wellbore414, which may be represented as “detaching” the simulated camera from the drilled wellbore414(or alternatively, the drill string). Detaching the simulated camera allows the visualization to present the drilled wellbore414, the original drill plan410, and other depictions from a different perspective. For example, it may include showing a side view of the 3-D depictions. Function424resets the view of the HMI400to the view depicted inFIG. 3with the display centered on the drilled wellbore414. Function426reorients the view of HMI400to the bottom of the drilled wellbore414with the depiction of the BHA428in the center. Function434, which includes arrow symbols, may be used to reorient the view of the HMI400to different positions along the drilled wellbore414. In some implementations, function434allows a user to travel up and down a depiction of the previous locations of the toolface and/or a depiction of the drill string. The drilled wellbore414may extend back from a depiction of a BHA428and may include a number of stations440(shown as spheres) showing survey locations.

FIG. 4shows a three-dimensional HMI500including a drilling window502and an adjusted ideal drilling path510. In some implementations, the HMI500may include one or more aspects of the HMI400shown inFIG. 3. For example, the HMI500may include three-dimensional depictions of a drill plan410, an adjusted ideal drilling path510, and a drilled wellbore414. The HMI500may also include an index504showing data related to the position of the BHA showing the position of the BHA428, or in the example ofFIG. 5, the position of the simulated camera.

In some implementations, a drilling window502is included in the HMI relative to a portion of the drill plan410or adjusted ideal drilling path510. In the example ofFIG. 5, the drilling window502has a rectangular shape with width w1and height h1. The drilling window502may be connected with other drilling windows (as shown inFIGS. 6 and 7) such that the drilling windows form extruded rectangular prisms along the drill plan410. In other implementations, the drilling window502may have other shapes, such as, for example, square, polygon, circle, ellipse, overall and/or irregular shapes. In some implementations, the adjusted ideal drilling path510is established during the drilling operation in response data received during the operation, for example, related to geology or equipment. The adjusted ideal drilling path510may represent an ideal route along which to steer the BHA428to achieve one or more objectives such as to maximize the production of the well or to avoid obstacles or areas in which maneuvering is more difficult. As indicated above, this may be based upon detected data, such as GEO steering data obtained from sensors or from other down hole information (e.g., mud evaluation at the surface). The adjusted ideal drilling path510may be placed in the center of the one or more drilling windows502. Since the drilling windows may be placed with horizontal and vertical offsets, as well as tilt angles relative to the drill plan410, the adjusted ideal drilling path510may include also include offsets and angular changes. In the example ofFIG. 4, the adjusted ideal drilling path510is offset to the left of the drill plan410and extends through the center of drilling window502.

Although a single drilling window502is shown inFIG. 4, in some implementations, a series of drilling windows502are placed along the drill plan410. In this case, the adjusted ideal drilling path510may pass through the center of each drilling window502. In the case where drilling windows502are extruded rectangular prisms, each drilling window502has centroid points where its diagonals intersect. If these centroid points are joined in a line passing through the three-dimension drilling window502, the adjusted ideal drilling path510may be configured to pass along this line. In the example ofFIG. 5, the drilling window502is disposed around a generally horizontal portion of the drill plan410. In some implementations, the one or more drilling windows502may be placed in a plane perpendicular to the longitudinally extending drill plan410. In other implementations, such as the example ofFIG. 7, the one or more drilling windows may be placed at an angle with respect to the drill plan410so as to have a “tilt.” The offsets and reorientation of the drilling windows502may represent updates to the drill plan410. For example, the drill plan410may include a section extending out horizontally with an inclination angle of 89.65 degrees, but after receiving real time gamma data (such as from the gamma sensor226as shown inFIG. 2), a geo-steering technician may advise the driller that the well needs to be drilled at 89.1 degrees instead. This change may be reflected by modifying the adjusted ideal drilling path510to extend with an inclination of 89.1 degrees. Later on, the geo-steering technician may determine that the wellbore should be drilled at another angle, such as 90.3 degrees. Therefore, the adjusted ideal drilling path510may be updated to 90.3 degrees. The adjusted ideal drilling path510may be adjusted instantaneously, along with the drilling windows502. Although the adjusted ideal drilling path510may include curved portions, in some implementations it is not subject to minimum curvature calculation models which depend on circular arc path models.

The adjusted ideal drilling path510may provide a more intuitive view of an ideal path along which to steer the BHA428, without requiring the driller to make complex geometric calculations during a drilling operation. Furthermore, the addition of the adjusted ideal drilling path510to visualizations such as HMI400may enable a comparison between the original drill plan410and the adjusted ideal drilling path510which may help in planning future drilling operation or for judging the performance of the current operation. The adjusted ideal drilling path510may also be used to generate steering targets ahead of the BHA428to optimize the steering path. These steering targets may be generated automatically by the controller and may be displayed on a display device such as HMI400for reference. Steering targets may be particular locations identified by a geo-steering operator and may be marked on the display device as a symbol. The display may also include a path to the steering target that may serve as a guide for an operator.

The drilling windows502may be generated with boundaries that define acceptable deviation from a drill plan410or an adjusted ideal drilling path510. As such, the drilling windows502may correspond with the drilling tolerance at a particular place on the drill plan or adjusted ideal drilling path. For example, the width w1may correspond with a tolerance in the x-direction (with respect to the drill plan410) and the height h1may correspond with tolerance in the y-direction. In the example ofFIG. 4, w1is about 60 feet and h1is about 30 feet. In this case, the drill plan is nearly horizontal, so the tolerance in the x-direction is a horizontal tolerance while the tolerance in the y-direction is a vertical tolerance. Some factors that may dictate the size or shape of the drilling window502may include proximity to other wellbores, whether planned or already drilled, geological formations including formations targeted and formations to be avoided, geological layer generally, the size of deposits, and other factors. In the example ofFIG. 4, the horizontal tolerance is greater than the vertical tolerance and so w1is greater than h1. This may be the case because during the horizontal portions of some drill plans, vertical errors can be more costly than horizontal errors due to the position of geological layers and/or a desire to have multiple wellbores close together. In other locations along the drill plan, such as vertical or near-vertical sections, the drilling windows502may have tolerances in the x- and y-directions that are nearly equal. In other implementations, the dimensions of the one or more drilling windows502may have other shapes, such as curves, polygons, circles, ellipses, and irregular shapes. These shapes may be chosen to conform to the drilling tolerances around a drill plan and may be changed throughout a drilling operation.

The orientation, position, and size of each drilling window502may be varied independently. In some implementations, the drilling windows502are centered on the drill plan410, while in other implementations, one or more drilling windows502are offset from the drill plan410. The drilling windows502may be placed at regular intervals along the drill plan410, such as about every 10 feet or 3 meters. In other implementations, drilling windows502are placed at about every 1 foot, at about every 20 feet, or at about every 50 feet. Some implementations include drilling windows spaced apart by a distance equivalent to a drill string stand. In one example, a drill string stand has a length between about 90 and 110 feet. The intervals between drilling windows502may be varied. For example, in difficult sections of the drill plan410, the drilling windows502may be placed closer together to help an operator more easily visualize the correct route. In the example ofFIG. 4, the drilling window502is roughly perpendicular to the drill plan410, but drilling windows may be placed at different angles relative to the drill plan410, such that each drilling window502has a particular tilt or “dip angle” relative to the drill plan410. Regardless of window spacing, the adjusted ideal drilling path extends through the windows providing an ideal target pathway for the driller.

The three-dimensional HMI500ofFIG. 4also shows a depiction of the drilled wellbore414. The depiction of the drilled wellbore414may include a depiction the BHA428in a location relative to the drill plan410and a projected position442of the BHA. In the example ofFIG. 4, the location of the BHA428is compared to the adjusted ideal drilling path510and the drilling window502by a controller in the drilling system (such as controller252as shown inFIG. 2). Information comparing these features is shown in index504. In some implementations, normal plan clearance calculations are carried out by the controller to compare the location of the BHA428to a drill plan410or an adjusted ideal drilling path510. These calculations may be based on points of interest along the drilled wellbore414as well as a corresponding point of interest on the drill plan410or the adjusted ideal drilling path510. The controller242may render results of the normal plane clearance calculations in polar directions and distances, which may be converted to a rectangular offsets by an algorithm run by the controller242. In the example ofFIG. 6, the distance between the location of the BHA428and the adjusted ideal drilling path510is shown by line506. The index504states that the location of the BHA428is 12.8 feet high and 3.1 feet right with respect to the adjusted ideal drilling path510.

The controller may also be configured to determine whether or not the drilled wellbore414(including the BHA at an end) is within the drilling window502. In some implementations, the proximity of the BHA428to the drilling window502is calculated at every station440(FIG. 3; corresponding to the performance of a survey). Proximity calculations may also be carried out by the controller at interpolated points along the drilled wellbore414and/or at a projected position442of the BHA428. In some implementations, the proximity calculations are carried out by the controller at every 10 feet or 3 meters. Other distances between calculations may be used, such as at every 1 foot, at every 20 feet, or at every 50 feet. Some implementations the calculations are carried out at increments spaced apart by a distance equivalent to a drill string stand. In one example, a drill string stand has a length between about 90 and 110 feet. These proximity calculations may be used to render a status in relation to the drilling window502(i.e., “in window” or “out of window”). In some implementations, the color of the drilling window502may represent the position of the drilled wellbore414in relation to the drilling window502. For example, the drilling window502may be green if the drilled wellbore414passes through it and red if the drilled wellbore does not pass through it. Other colors are possible, as well as patterns, shapes or other graphical representations to show the status of the drilling window502.

In some implementations, the controller252is configured to store the status of each drilling window with respect to the BHA and calculate a length of the drilled wellbore that was drilled within drilling windows502. This length may be used as a Key Performance Indicator (KPI) for the drilling operation, by comparing the percentage of the drilled wellbore that was drilled within the drilling windows502compared to the entire drilled wellbore. This KPI may be displayed by a display device in the drilling system, such as on the HMI500or on control windows600as shown inFIG. 7. In some implementations, the results of every drilling window502may be viewed independently, such as in x-y graph format.

FIG. 5shows an exemplary representation of an HMI520that includes aspects of the HMI400shown inFIG. 3and the adjusted ideal drilling path510and drilling window502of HMI500shown inFIG. 4. In some implementations, the concentric circular grid402, advisory segment404, symbols406, and indicator408are overlaid on the three-dimensional depictions of the drilled wellbore414, the adjusted ideal drilling path510, and the drilling window502. In some implementations, the indicator408may be positioned to show a driller an ideal route for placing the BHA428on the adjusted ideal drilling path510. In other implementations, the indicator408may be positioned to show a driller an ideal route for placing the BHA428in a portion of the drilling window502or the drill plan410. In some implementations, the concentric circular grid402, advisory segment404, symbols,406, and indicator408may be added or removed from the HMI520as desired by the operator by using the user interface260(as shown inFIG. 2). This functionality may allow an operator to view more specific data if required without distracting from other aspects of the visualizations.

FIG. 6shows a graphical representation540of an adjusted ideal drilling path570and a series550of drilling windows including drilling windows551,552,553,554,555, and556. Each drilling window of the series550may be similar to the drilling window502show inFIGS. 4 and 5. The graphical representation540may also include a depiction of a drill plan562which may appear as a long, three-dimensional cylinder. The drilling windows of the series550may be shown relative to a drill plan562, and each drilling window of the series550may correspond to an index location564on the drill plan562. The index location564may represent a location where the BHA or a portion of the adjusted ideal drilling path570is compared to the respective drilling window of the series550. In some implementations, each drilling window of the series550has the shape of an extruded rectangular prism. The face of each drilling window of the series550is shown with a dark unbroken line, and the three-dimensional extension of each drilling window is shown by the dotted lines566(for example, in reference to drilling window556). In the example ofFIG. 6, each drilling window of the series550abuts another drilling window, such that the entire drill plan562is covered or encompassed by the window and the extension. The drilling windows of the series550may include various colors and patterns to indicate if a drilled wellbore, passes through them. For example, the color of a drilling window may appear as green if a drilled wellbore passes through it and red if a drilled wellbore does not pass through it. Other colors and patterns may be used.

The graphical representation may also include an adjusted ideal drilling path570that is represented by a thick unbroken line. The adjusted ideal drilling path570may pass through a central location of each of the drilling windows of the series550. In the example ofFIG. 6, each drilling window of the series550is centered on the drill plan562, so the adjusted ideal drilling path570passes through the center of or is coaxial with the drill plan562. This may indicate that the drill plan562represents an optimized route according to factors such as production potential, damage or obstacle avoidance, and drilling efficiency.

Each drilling window of the series550may have a particular shape, size, position, and orientation with respect to the drill plan562. For example, the drilling windows of the series550have a rectangular shape with widths and heights that are approximately equal and extend back into rectangular prism shapes that are approximately the same size. However, the drilling windows of the series550may have other sizes and shapes, for example, square, polygon, circle, ellipse, and/or irregular shapes. In the example ofFIG. 6, each drilling window of the series550is centered on the drill plan562and oriented in planes generally perpendicular to the drill plan562. However, as shown inFIG. 7, the drilling windows of the series549may be offset from the drill plan562and/or oriented at different angles from the drill plan562.

FIG. 7shows a graphical representation560of an adjusted ideal drilling path570series549of drilling windows including drilling windows551,552,553,554,555,556and a drill plan562. In this example, adjusted ideal drilling path570includes deviations from the original drill plan562. The drilling windows of the series549have been offset and rotated in response to data (such as survey data) received during the drilling operation. In some implementations, this data includes sensor data received by various components on the drilling apparatus, including sensors on a BHA (such as the gamma sensor226as discussed in reference toFIG. 2) as well as survey data and data received from external sources (such as geological information from other drilling operations or rigs).

Drilling windows552,553,554, and555have been offset vertically (with respect to the drill plan562) from their original positions inFIG. 6. In particular, drilling window552has been offset slightly horizontally such that the drill plan562passes through the drilling window552, whereas drilling windows553,554, and555have been offset such that the drill plan562does not pass through them. The drilling windows of the series549may also be offset in a horizontal direction with respect to the drill plan562.

The drilling windows of the series549may also be positioned with various orientations with respect to the drill plan562. For example, drilling window553is positioned with a tilt angle α1and drilling window555is positioned with a tilt angle α2with respect to a plane perpendicular to the drill plan562. In some implementations, angles α1may measure between 15 and 25 degrees, between 0 and 30 degrees, between 30 and 60 degrees, or between 0 and 180 degrees, as well as other measurements. The drilling windows of the series549may be positioned with tilt angles in a lateral direction (i.e., side to side with respect to the drill plan562) and/or in a horizontal direction (i.e., forward or backward with respect to the drill plan562). The three-dimensional shape of each drilling window of the series549may include a similar orientation along various surfaces, such as shown in the example ofFIG. 7.

The graphical representation may include an adjusted ideal drilling path570. In some implementations, the adjusted ideal drilling path570may be represented by a solid line (as shown in the example ofFIG. 7), a dashed line, or another type of line, and may be colored or patterned in a particular way to distinguish it from other features. As discussed above, the adjusted ideal drilling path570may represent an ideal path along which to drill the BHA of the drilling apparatus based on adjustments while drilling to modify the ideal adjusted ideal drilling path from the original well plan.

In some implementations, the adjusted ideal drilling path570may pass through one or more of the drilling windows of the series549. The adjusted ideal drilling path570may include portions which extend along horizontally, vertically, along an angle, stepped portions, and/or curved portions. In the example ofFIG. 7, the adjusted ideal drilling path570includes portions which extend at angles β1and β2. In some implementations, these angles β1and β2may be related to angles α1and α2of drilling windows553and555. For example, the drilling windows553and555may be place on a plane that is perpendicular to the portion of the adjusted ideal drilling path570that extends through drilling windows553and555. The adjusted ideal drilling path510may provide the driller with an accurate, real time drilling target during the drilling operation.

FIG. 8Ashows an exemplary control panel600that may be used to generate, visualize, and make changes to drilling windows which may be used to generate an adjusted ideal drilling path. In some implementations, the adjusted ideal drilling path is generated by forming a line through the center of each drilling window. However, this is only one example of generating an adjusted ideal drilling path. Other examples include generating the adjusted ideal drilling path independent of any drilling windows. In either case, the drilling windows may displayed or hidden from a display based on a setting. The drilling windows discussed inFIG. 8Amay be any of the drilling windows502,551,552,553,554,555,556as discussed in reference toFIGS. 4 and 5. Control panel600may include main window602and change window604. Main window602may include a diagram610of a drilling window, a list612of drilling windows, option icons614, and a feedback icon616. The diagram610of the drilling window may show a two-dimensional representation of a selected drilling window of the list612of drilling windows, including the dimensions of the drilling window. The locations of a drill plan, an adjusted ideal drilling path, and/or a drilled wellbore may be shown in relation to the drilling window in the diagram610. Colors representing the location of the drilled wellbore (for example a green area that is highlighted if the drilled wellbore passes through the drilling window and a red area that is highlighted if the drilled wellbore does not pass through the drilling window) may be shown in the diagram610.

The list612of drilling windows may show parameters relating to each drilling window, such as its depth and position along the drill plan, the width and height of the drilling window, the offsets of the drilling window with respect to the drill plan and other drilling windows, and an inclination and tilt angle of each drilling window, as well as other parameters. Reasons for different dimensions, offsets, and tilt angles may be recorded on the list612. For example, the seventh drilling window on list612has a width of 40 feet, a height of 9 feet, an offset of 6 feet from the sixth drilling window, an inclination of 89.77 degrees, and a dip angle (or tilt angle) of 0.23 degrees. The reasons for one or more of these changes are listed “as per geology,” signaling that the changes were made to account for a geological issue around the drill plan. An operator may add new drilling windows to the list612by using the option icons614. In this case, the new drilling windows may be displayed in the visualization such as HMI400and500.

The parameters of each drilling window may be independently changed through the use of the change window604. The change window604may allow an operator to change any of the parameters of the drilling window as discussed above. The change window604may also allow the operator to include comments related to changes. The operator may give feedback about the drilling window or other operations through the use of the feedback icon616.

FIG. 8Bshows an exemplary control panel700that may be used to generate, visualize, and make changes to a drill plan, including generating an adjusted ideal drilling path. The control panel700may be accompanied by a visualization710of an original drill plan720, and adjusted ideal drilling path722, and several drilling windows724. The control panel700may show data corresponding to an adjusted ideal drilling path that has been generated by modifying a drill plan. In the example ofFIG. 8B, the original drill plan720extends underground along a roughly horizontal path. The original drill plan720has been changed four times as shown at references712,714,716, and718. At reference712, the depth of the drill plan720is changed by adding a true vertical depth (TVD) offset of depth (A). The dotted line representing the new adjusted ideal drilling path722is shown along with a drilling window724indicating drilling tolerances around the adjusted ideal drilling path722. At references714and716, the adjusted ideal drilling path722is modified by changing the dip angle of the wellbore (with angles (B) and (C)). At reference718, the adjusted ideal drilling path722is modified by another TVD offset (with depth (D)). In some implementations, the control panel700may be used to keep track of the modifications that have been made to a drill plan720or adjusted ideal drilling path722for the operator's reference.

FIG. 9is a flow chart showing a method800of visualizing and steering a BHA in a down hole environment. It is understood that additional steps can be provided before, during, and after the steps of method800, and that some of the steps described can be replaced or eliminated for other implementations of the method800. In particular, any of the control systems disclosed herein, including those ofFIGS. 1 and 2, and the displays ofFIGS. 3-8B, may be used to carry out the method800.

At step802, the method800may include inputting a drill plan. This may be accomplished by entering location and orientation coordinates into the controller252discussed with reference toFIG. 2. The drill plan may also be entered via the user interface, and/or downloaded or transferred to controller252. The controller252may therefore receive the drill plan directly from the user interface or a network or disk transfer or using other systems or means.

At step804, the method800may include conducting a drilling operation with a drilling apparatus comprising a motor, a BHA, and one or more sensors. In some implementations, this drilling apparatus is apparatus100discussed in reference toFIG. 1. The drilling apparatus may be operated by an operator who inputs commands in a user interface that is connected to the drilling apparatus. The BHA may be disposed at the end of a drill string. The operation may include drilling a hole to advance the BHA through a subterranean formation.

At step806, the method800may include receiving with a controller sensor data associated with the BHA. This sensor data can originate with sensors located near the BHA in a down hole location, well as sensors located along the drill string or on the drill rig as described and shown with reference toFIGS. 1 and 2. The sensor data may include data from surveys conducted down hole. In some implementations, a combination of controllers, such as those inFIG. 2, receive sensor data from a number of sensors via electronic communication. The controllers may transmit the data to a central location for processing.

At step808, the method800may include generating a depiction of the drill plan with the controller. In some implementations, the depiction of the drill plan is similar to drill plan410as shown inFIGS. 3-5. The depiction of the drill plan may be shown in a three-dimensional visualization such as that shown in HMIs400,500, and520and may be displayed on any type of display device, such as a computer monitor. The drill plan may appear as a line passing through a three-dimensional environment (as shown inFIGS. 3-5) and may be used as a reference for the operator during the drilling operation.

At step810, the method800may include generating an adjusted ideal drilling path. The adjusted ideal drilling path may represent an ideal path for the operator to drive the BHA and may reflect deviations from the original drill plan. The adjusted ideal drilling path may be generated by the controller based on data detected during the drilling process, such as geological data. The adjusted ideal drilling path may appear as a three-dimensional shape, such as a long, three-dimensional cylinder, and may be distinguished from the depiction of the drill plan by color, pattern, size, and/or other visual cues. The adjusted ideal drilling path may include changes in direction that differ from the drill plan.

At step812, the method800may include determining the position of the BHA. The controller may make this determination after receiving sensor data received from the sensor system on the drilling apparatus related to the position of the BHA. The position of the BHA may also be determined by receiving and analyzing survey data collected throughout the drilling operation.

At step814, the method800may include displaying the position of the BHA and the adjusted ideal drilling path. The depiction of the BHA and adjusted ideal drilling path may be similar to the depiction of the BHA428and adjusted ideal drilling path as shown inFIGS. 3-5. The displayed features may be accompanied with visualization tools such as targets, direction lines, and measurements, as well as data displayed in text format. In some implementations, the depiction of the BHA includes a depiction of the drilled wellbore (such as the depiction of drilled wellbore414inFIGS. 3-5) or the route along which the BHA has traveled, with the depiction of the BHA at the end. The display may also include data comparing the position of the BHA to the adjusted ideal drilling path, such as measurements of the distance and polar directions between the BHA and the drilling windows or adjusted ideal drilling path. In some implementations, these measurements are converted to rectangular offsets. In some implementations, the display may also include one or more drilling windows as shown inFIGS. 3-8B. These drilling windows may indicate drilling tolerances around the adjusted ideal drilling path and may be displayed or hidden by selecting an option on the display.

At step816, the method800may optionally include generating one or more drilling windows with the controller. The one or more drilling windows may be similar to any of the drilling windows502,551,552,553,554,555, or556as shown inFIGS. 3-8B. In some implementations, a series of drilling windows is generated along the entire length of an adjusted ideal drilling path. The one or more drilling windows may appear as two- or three-dimensional shapes in the visualization and may be placed relative to the adjusted ideal drilling path. The parameters of the drilling windows may be individually varied as they are generated, as well as during the drilling operation as conditions change. In some implementations, the drilling windows may be generated with an offset (i.e., horizontal or vertical) and/or a tilt angle with respect to the adjusted ideal drilling path. The offsets and/or tilt angles of the drilling windows may represent updates to the adjusted ideal drilling path due to new information received by the controller in regards to the drilling operation. The new information may include the data obtained by the sensors.

At step818, the method800may optionally include directing the drilling apparatus using the adjusted ideal drilling path and/or drilling windows as a reference. The adjusted ideal drilling path and the one or more drilling windows may provide an easy to understand representation of the tolerances along the drill plan and the ideal route for which the operator should direct the BHA. The operator may use the depiction of the drilling windows as well as the ongoing comparison of BHA position and the one or more drilling windows to see an intuitive view of the down hole environment and to make informed steering decisions.

In view of all of the above and the figures, one of ordinary skill in the art will readily recognize that the present disclosure introduces a method of directing operation of a drilling system, including: drilling with a bottom hole assembly comprising a bottom hole assembly (BHA) disposed at an end of a drill string to create a drilled bore substantially following an original drill plan; receiving sensor data relating to geological formations from one or more sensors adjacent to or carried on the bottom hole assembly; receiving a drilling instruction that is different than the original drill plan; generating, with a controller, an adjusted ideal drilling path in response to the drilling instruction; determining, with the controller, a position of the bottom hole assembly based on the received sensor data; and displaying, on a display device, the position of the bottom hole assembly relative to the adjusted ideal drill path.

In some implementations, the method further includes generating one or more drilling windows around the adjusted ideal drilling path, the one or more drilling windows representing a drilling tolerance at a portion of the adjusted ideal drilling path around which the one or more drilling windows are generated. The adjusted ideal drilling path may pass through a center of the one or more drilling windows. The method may also include generating the one or more drilling windows with a three-dimensional extruded rectangle shape.

In some implementations, each of the one or more drilling windows is assigned one or more of a vertical offset, a horizontal offset, and a tilt angle with respect to the adjusted ideal drilling path. The method may include using the position of the bottom hole assembly relative to the adjusted ideal drilling path as a reference to change the position of the bottom hole assembly. In some implementations, determining a position of the bottom hole assembly comprises determining a position of the BHA, the method further comprising displaying the position of the BHA relative to the adjusted ideal drilling path on a three-dimensional display. The method may also include displaying, on the display device, instructions to direct the bottom hole assembly to the adjusted ideal drilling path.

A drilling apparatus is also provided, including: a drill string comprising a plurality of tubulars and a bottom hole assembly (BHA) operable to perform a drilling operation; a sensor system configured to detect one or more measureable parameters of a geological formation; a controller in communication with the sensor system, wherein the controller is operable to generate a visualization comprising a depiction of an adjusted ideal drilling path representing a deviation from an original drill plan and a depiction of a location of the drill string based on the one or more measurable parameters of the geological formation; and a display device in communication with the controller, the display device configured to display to an operator a visualization comprising the depiction of the location of the drill string and the adjusted ideal drilling path.

In some implementations, the one or more measureable parameters of the geological formation comprise an inclination measurement, an azimuth measurement, a toolface angle of the BHA, and a hole depth. The controller may be further operable to generate a three-dimensional depiction of the original drill plan, wherein the visualization further comprises the depiction of the original drill plan. The controller may be further operable to generate one or more drilling windows around the adjusted ideal drilling path, the one or more drilling windows representing a drilling tolerance at a portion of the adjusted ideal drilling path around which the one or more drilling windows are generated. The one or more drilling windows may have a three-dimensional extruded rectangle shape. The display device may be further configured to display instructions to direct the BHA to the adjusted ideal drilling path.

An apparatus for steering a bottom hole assembly (BHA) is also provided, including: a controller configured to: receive data representing a drill plan of a drilling operation and measured parameters indicative of positional information of the BHA in a down hole environment; receive drilling data during the drilling operation and generate one or more updates to the drill plan; generate an adjusted ideal drilling path that is different than the drill plan based on the updates to the drill plan; and determine a location of a most recent BHA position based on the measured parameters indicative of positional information; and a display device in communication with the controller and viewable by an operator, the display device configured to display a visualization comprising a three-dimensional depiction of the most recent BHA position and the adjusted ideal drilling path.

In some implementations, the controller is further configured to generate one or more drilling windows around the adjusted ideal drilling path, the one or more drilling windows representing a drilling tolerance at a portion of the adjusted ideal drilling path around which the one or more drilling windows are generated. The adjusted ideal drilling path may extend through a center of each of the one or more drilling windows. The controller may be further configured to generate a three-dimensional depiction of the drill plan. The controller may be operable to compare the most recent BHA position and the adjusted ideal drilling path and display a distance between the BHA position and the adjusted ideal drilling path on the display device. The display device may be further configured to display instructions to direct the BHA to the adjusted ideal drilling path.

Moreover, it is the express intention of the applicant not to invoke 35 U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the word “means” together with an associated function.