ACTIVE MONITORING OF ALIGNMENT OF RIG COMPONENT

Abstract

A tool for use in subterranean operations can include a top drive and an alignment sensor coupled to the top drive. The alignment sensor can measure an alignment condition of a first rig component relative to an alignment position. A system for wellbore operations can include the tool and generate an alarm signal upon misalignment of rig components prior to damage of the equipment.

Description

CROSS-REFERENCE TO RELATED APPLICATION

The present application claims priority to U.S. Patent Application No. 62/186,866, filed Jun. 30, 2015, entitled “Active Monitoring of Alignment of Rig Component”, naming as an inventor Scott Boone, which application is incorporated by reference herein in its entirety.

FIELD OF DISCLOSURE

The present disclosure relates generally to wellbore drilling operations, and more particularly to measuring an alignment condition of a rig component.

BACKGROUND

Drilling subterranean wells for oil and gas is expensive and time consuming. Formations containing oil and gas are typically located thousands of feet below the earth's surface. To access the oil and gas, thousands of feet of rock and other geological formations must be removed. To ensure a cost-effective drilling operation, equipment utilized in wellbore drilling operations must be capable of repeated, reliable operation. Damage to components of a drilling rig due to misalignment in the wellbore can cause equipment to fail and can shut down an operation, rendering the drilling operation economically unsustainable. The industry continues to demand improvements in subterranean drilling operations.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments are illustrated by way of example and are not limited in the accompanying figures.

FIG. 1 includes a schematic view of a drilling rig.

FIG. 2 includes a partially cut away front perspective view of a junction box disposed on a top drive in accordance with an embodiment.

FIG. 3 includes a side perspective view of FIG. 2.

FIG. 4 includes a simplified schematic of an active sensing and continuous (real time) information relaying operation adapted to sense and actively relay an alignment condition in accordance with an embodiment.

Skilled artisans appreciate that elements in the figures are illustrated for simplicity and clarity and have not necessarily been drawn to scale. For example, the dimensions of some of the elements in the figures may be exaggerated relative to other elements to help to improve understanding of embodiments of the invention.

DETAILED DESCRIPTION

The following description in combination with the figures is provided to assist in understanding the teachings disclosed herein. The following discussion will focus on specific implementations and embodiments of the teachings. This focus is provided to assist in describing the teachings and should not be interpreted as a limitation on the scope or applicability of the teachings. However, other embodiments can be used based on the teachings as disclosed in this application.

The terms “comprises,” “comprising,” “includes,” “including,” “has,” “having” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a method, article, or apparatus that comprises a list of features is not necessarily limited only to those features but may include other features not expressly listed or inherent to such method, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive-or and not to an exclusive-or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

Also, the use of “a” or “an” is employed to describe elements and components described herein. This is done merely for convenience and to give a general sense of the scope of the invention. This description should be read to include one, at least one, or the singular as also including the plural, or vice versa, unless it is clear that it is meant otherwise. For example, when a single item is described herein, more than one item may be used in place of a single item. Similarly, where more than one item is described herein, a single item may be substituted for that more than one item.

Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. The materials, methods, and examples are illustrative only and not intended to be limiting. To the extent not described herein, many details regarding specific materials and processing acts are conventional and may be found in textbooks and other sources within the drilling arts.

The concepts are better understood in view of the embodiments described below that illustrate and do not limit the scope of the present invention. The following description includes a tool for wellbore operations. Certain embodiments of the tool can include a sensor adapted to measure an alignment condition of a rig component. The alignment condition can include the relationship between the actual position of the rig component and its alignment position. As used herein, the term “alignment position” refers to a reference position used to determine the alignment of the rig component and will be discussed in more detail below. In certain embodiments, the tool can measure the alignment condition continuously (in real-time) and relay the condition to a user. Further, the description includes a system for use in subterranean operations. The system can include a sensor and a computing system in communication with the alignment sensor to determine, for example, adjustments to the rig component based on its alignment condition. Furthermore, the description includes a method of operating a system for subterranean operations. The method can include acquiring an alignment condition and adjusting a rig component to change the alignment condition of the rig component.

The term “alignment condition” refers to the alignment status of the rig component based on the proximity of the rig component to its alignment position. In certain embodiments, the alignment condition can include at least an aligned condition, where the proximity of the rig component to its alignment position is within an acceptable range, and a misaligned condition, where the proximity of the rig component to its alignment position is outside of an acceptable range.

In certain embodiments, the proximity of the rig component to its alignment position can include the angle of departure of the actual position of the rig component from the alignment position. For example, sensing and generating data regarding an alignment condition can include measuring an angle of departure of the actual position of the rig component (or an axis of the rig component) from an alignment position. In particular embodiments, the angle of departure can include a pitch angle, a roll angle, or both. In further embodiments, the tool can be sensitive enough to comply with the engineered tolerances of the machine being used. For example, the angle of departure can be measured at an interval sensitivity of at least 0.1°, at least 0.01°, or at least 0.001°.

The smaller the angle of departure, the closer the rig component is to its alignment position. For example, the actual position of the rig component can approach an aligned alignment condition as the angle of departure approaches 0°. In certain embodiments, the alignment condition includes an aligned alignment condition when the angle of departure is no greater than 5°, no greater than 1°, no greater than 0.5°, or even no greater than 0.1°.

Conversely, the larger the angle of departure, the farther the rig component is from its alignment position. For example, the actual position of the rig component can approach a misaligned alignment condition when the angle of departure moves away from 0°. In certain embodiments, the alignment condition includes a misaligned alignment condition when the angle of departure is at least 0.1°, at least 0.5°, at least 1°, or even at least 5°.

As stated previously, an alignment position is a reference position used in determining the alignment condition of the rig component. In certain embodiments, the alignment position can include at least one axis, at least two axes, or even at least three axes. For example, the alignment position can include a uniaxial alignment position including a first axis. As another example, the alignment position can include a biaxial alignment position including a first axis and a second axis. In any type of alignment position, one or more of the at least one axis can include a predetermined axis.

In certain embodiments, the alignment position can include a first axis and a second axis where the first axis and the second axis are different compared to each other. In particular embodiments, the first axis can be orthogonal to the second axis. For example, in any type of alignment, the first axis can include true vertical or true horizontal. Thus, in a biaxial alignment position, the first axis can include true vertical and the second axis can include true horizontal, and vice versa. Further, instead of true vertical or true horizontal, in any type of alignment the first axis or second axis can be greater than 0° from true vertical or from true horizontal, such as greater than 0° and less than 90° from true vertical or from true horizontal. Furthermore, in any type of alignment position, the first axis or second axis can include an axis of a second rig component. The second rig component can include, for example, a top drive, guide tracks a top drive, running gear disposed on a top drive, or any combination thereof. Also, the second rig component can include a quill, a drill string or at least a portion of a drill string, such as a top portion of a drill string.

In accordance with an embodiment of the present invention, FIG. 1 is a simplified schematic of a subterranean drilling operation 100. The drilling rig 100 can be an offshore drilling rig or a land based drilling rig. Offshore drilling rigs can take many forms. For example, the drilling rig 100 can have a fixed platform or substructure attached to an underlying seabed. Alternatively, the drilling rig 100 can include a floating platform disposed at least partially underwater with an anchoring system holding the drilling rig 100 relatively near the underwater drilling operation. It should be understood that the particular configuration and embodiment of the drilling rig 100 are not intended to limit the scope of the present disclosure.

As illustrated in FIG. 1, the drilling rig 100 can generally include a substructure 102 and a derrick 104. The derrick 104 can be attached to the substructure 102 and can extend therefrom. The derrick 104 can be a tower or a guyed mast such as a pole which can be hinged at a bottom end. The derrick 104 and substructure 102 can be permanent or can be adapted to break down for transportation. In certain embodiments, the drilling rig 100 can further include a hoisting system 106, a top drive 108, and a power supply 110. While a top drive 108 is shown, the principles of this disclosure can apply to any drive system including a top drive, a power swivel or a rotary table. The derrick 104 can support the hoisting system 106 and the top drive 108. In a particular embodiment, the hoisting system 106 can include a drawworks 114 and a block and tackle system 116 adapted to support a drill string 118.

Typically, a top drive is suspended from the derrick and is connected to a drill string via a main drive shaft (a short section of pipe known as a quill). The top drive rotates the quill which, in turn, rotates the drill string and the drill bit to produce a well bore. A misalignment of the top drive and the drill string can result in damage to the quill, which can cause equipment to fail and can shut down an operation. Manual alignment of the top drive and the drill string relative to an alignment position, such as true vertical, has proven to be either inaccurate or unable to account for misalignments that occur during operation. For example, the top drive can be suspended in the derrick by a traveling block that allows the top drive to move up and down the derrick where misalignment can occur. Further, mobile drill rigs have been developed that are capable of “walking” about a location and such movements are capable of resulting in a misalignment. Even when stationary, rig foundations can shift or settle. Such movement can result in a misalignment that occurs during operation that can damage rig components, such as the top drive or the drill string. Proper orientation should be monitored during operation to assist in realigning the mast sections or the top drive and avoiding damage to the rig components.

In a particular aspect, at least one alignment sensor 200 (see FIG. 4) can be coupled to an equipment of the drilling rig 100 to actively sense and generate data regarding an alignment condition of a rig component relative to an alignment position. As used herein, “actively sense” refers to an act of sensing where a sensing condition occurs at least once every hour, such as at least once every 30 minutes, at least once every minute, or even at least once every 10 seconds. In a particular embodiment, “actively sense” refers to an act of sensing wherein a sensing condition occurs at least 1 time per minute (TPM), such as at least 30 TPM, at least 60 TPM, at least 120 TPM, or even at least 300 TPM. Moreover, in particular embodiments, the alignment sensors can sense the condition no greater than 5,000 TPM, such as no greater than 4,000 TPM, no greater than 3,000 TPM, no greater than 1,000 TPM, no greater than 500 TPM, or even no greater than 300 TPM.

The alignment sensor should be disposed in a location that allows the alignment sensor to measure the alignment condition. For example, the at least one alignment sensor 200 can be coupled to the top drive 108, or integrated into a remote panel on the top drive 108, such as in the junction box 120 illustrated in FIGS. 2 and 3. FIG. 2 includes a front view of the junction box 120 relative to an x-axis and FIG. 3 includes a side view of the junction box 120 relative to a y-axis along the same plane as the x-axis. Further, the alignment sensor can be disposed in a fixed position on the top drive. The alignment sensor can be fixed in various ways including adhering the alignment sensor to the top drive. From the top drive, the alignment sensor can track the alignment condition (as discussed previously) to determine, for example, the misalignment of the top drive relative to the mast.

In certain embodiments, the alignment sensor can include an alignment sensor that can measure the angle of inclination of a rig component. For example, the alignment sensor can include an inclinometer. In particular embodiments, the inclinometer can include a microelectromechanical system (MEMS) or a nanoelectomechanical system (NEMS). In more particular embodiments, the inclinometer can include a dual axis inclinometer. The dual axis inclinometer can be configured to measure pitch and roll inclination. In further embodiments, the inclinometer can include a bubble inclinometer.

In addition, the alignment sensor can include a linear alignment indicator. For example, the linear alignment indicator can include a laser alignment system. In certain embodiments, a laser alignment head can be coupled to a rig component, such as the top drive. The laser alignment head can direct a laser to a desired target indicating an alignment condition based on whether the laser engages with the target. In embodiments, the target can include a visual target where a user determines alignment based on visual perception of whether the laser engages the target. In other embodiments, the target can include a sensor target that can determine whether the laser engages the target without the visual perception of a user. In particular embodiments, the linear alignment indicator can be used in combination with the sensor measuring the angle of inclination. For example, the linear alignment indicator can measure offset alignment and the inclination sensor can measure angular alignment.

In certain embodiments, the data from the alignment sensor, including an alignment condition of a rig component, can be transmitted, such as transmitted to a computing system. The data can be transmitted to assist in realignment of the rig components. As discussed in more detail below, the computing system can display the alignment condition on a human-machine interface (HMI), and the HMI can display the alignment condition using adjustable models of the rig components or other indicators of the alignment condition.

In certain embodiments, the alignment sensor 200 can be disposed outside a housing, or in communication with an intermediary member disposed outside of the housing by electrical wiring extending through the housing or a wireless signal. In this regard, the alignment sensor 200 can communicate the sensed alignment condition to an intermediary member located outside of the housing of the equipment. In another embodiment, the alignment sensors 200 can be directly engaged with a logic element 202, independent of an intermediary member. The logic element 202 may be disposed immediately proximate to the alignment sensors.

In a non-limiting embodiment, it may be advantageous to position at least a portion of each alignment sensor 200 at a location whereby the alignment sensor 200 can be reached and affected from an exterior location of the equipment. In another non-limiting embodiment, the alignment sensor 200 can be coupled to a portion of the equipment that can be readily removed or opened in order to expose the alignment sensor, e.g., a sealable hatch or access point. In such a manner, the alignment sensor 200 can be manipulated, adjusted, or even replaced without requiring significant operation upon the equipment.

Referring now to FIG. 4, during drilling operations, one or more alignment sensors 200 can actively monitor an alignment condition of the first rig component. For example, the alignment sensor can be monitored as part of a rig control system. After being collected by the alignment sensors 200, a sensed data relating to the alignment condition of the first rig component can be transferred (illustrated by line 208) continuously (in real time) to a logic element 202. As used herein “transferred continuously” refers to a transmission of data at least once every hour, such as at least once every 30 minutes, at least once every minute, or even at least once every 10 seconds. In a particular embodiment, “transferred continuously” refers to a transmission of data at least once every 30 minutes. In yet a more particular embodiment, “transferred continuously” refers to the transmission of data as it is obtained at each sensed interval, i.e., data is immediately transferred from the alignment sensors to the logic element. In a particular embodiment, a memory storage unit can be attached to the alignment sensors 200 for the temporary storage of the sensed data prior to transfer. The memory storage unit can further include a back up power supply.

In certain embodiments, the sensed data can be transferred to the logic element 202 as one or more data streams over a network or other wireless signal. The data can be transmitted within a working environment including the drilling rig. In addition, in certain embodiments, a remote communication element can relay the sensed data, such as through a satellite relay system, to a remote geographic location, disposed at a location different than the drill rig. In a particular embodiment, the transfer format and protocol can be based on the industry WITSML format, which uses XML as a data format and web services over HTTPS as a protocol. In another embodiment, the sensed data can be transferred directly to the logic element 202 by wiring or by another non-wireless local communication system, such as a LAN network. In such a manner, the logic element 202 can be disposed at a location on, or proximate to, the drill rig. In yet another embodiment, the logic element can include a plurality of interconnected logic elements. The interconnected logic elements can all be disposed at a single location or at separation locations interconnected by network or wireless signal.

In a particular embodiment, the logic element 202 can include a programmable logic controller, such as computer software. The logic element 202 can be adapted to receive a signal generated by the alignment sensor 200, the signal containing sensed data regarding the alignment condition of the first rig component.

Utilizing the data contained in the signal, the logic element 202 can perform a calculation and generate an alarm signal when the sensed alignment condition deviates from an accepted value by more than 5%, such as when the condition deviates from the accepted value by more than 10%, or even when the condition deviates from the accepted value by more than 15%. The alarm signal can indicate to a user or drilling engineer that the alignment condition, such as the angle of departure, of the first rig component is outside of an acceptable range of the accepted value. For example, the data from the alignment sensor can be transmitted to assist a rig crew to realign either the mast sections or the top drive (as will be discussed in more detail below).

In a particular embodiment, the accepted value can be programmed by a user, i.e., a user can formulate an acceptable value for the measured conditions and set the accepted value accordingly in the logic element. Moreover, the value for the angle of departure can be custom selected based on operational factors. In this regard, a user can adjust the deviation calculation based on environmental factors or risk assessment. For example, in harsh climates, e.g., deep water, dessert, or tropical locations, a lower deviation (e.g., 1° from alignment position) can be utilized as the alarm generating condition. In less risk averse drilling operations, e.g., small scale on-land operations, a higher deviation (e.g., 5° from alignment position) can be utilized as the alarm generating condition. In such a manner, risk can be assessed and addressed on a per operation manner.

In another embodiment, the accepted value can be set by one or more of the previously sensed conditions, e.g., the accepted value can be determined based on a previously sensed value of the condition. For example, the accepted value can be determined by a first value sensed by the alignment sensor, to which all future deviations are measured and compared against. If a later sensed value deviates from the initially allotted value to a degree beyond the allotted deviation, an alarm signal can be generated.

After performing an analysis of the sensed condition, the logic element 202 can communicate (illustrated by lines 210) a signal to an interface 204. The interface 204 can include a user interface adapted to display the signal from the logic element 202. In this regard, a user can visually determine the alignment condition (pitch and roll angle) of the rig component. In another embodiment, the logic element 202 can transfer the signal to an interface 206 located at the drill site.

In certain embodiments, the interface 204 can display to a user one of two indications: an indication that the sensed condition of the alignment condition is within the acceptable range (i.e., aligned); or an indication that the sensed alignment condition is outside of the acceptable range (i.e., misaligned). A third indication may optionally indicate to the user that the alignment condition is approaching the limits of acceptable deviation, i.e., the rig components may need to be realigned soon. Furthermore, in certain embodiments, the interface 204 can display a series of escalating alerts depending on the alignment condition.

In certain embodiments, the interface 204 can provide a real-time numerical visualization of the sensed alignment condition of the rig component. In this regard, the interface 204 may further include a visualization tool including graphical comparisons through time-indexed graphs. The visualization tool may be capable of illustrating qualitative parameter values, trends, interpreted activities, interesting events, etc. for the purpose of enhancing overall operation. For example, in particular embodiments, the alignment sensor measurements can be monitored by a computer versus time and its position in the mast of the rig. In addition, models of the adjustable sections of rig, such as the mast, the top drive, and the top drive support system, can be used to help direct the rig crew on how to adjust various rig components to achieve an aligned alignment condition. Additionally, in certain embodiments, the computing system can adjust a misaligned rig component based on the data received from the alignment sensor, including the alignment condition of the rig component.

In the case of a rapid fluctuation of the sensed alignment condition, a visualization tool may not be sufficient to rapidly alert of impending misalignment causing damage to the rig components. In this regard, in certain embodiments it may be desirable to include an indicator to indicate whether the alignment condition of the rig component is within or outside of the acceptable range.

The interface 204 can additionally include a data analysis server. Drilling engineers and other users and operators can use a client application running a personal computer or other computing device to connect from the drilling rig site or an operations center to the data analysis server in order to receive and display the sensed data. Once connected, the client application can be continuously updated with information from the data analysis server until such a time as the client is closed. In a particular embodiment, the data analysis server can be a program written in a Java programming language. The preferred client application can also be a Java application. The protocol between the client application and the server application can be based on regular polling by the client application using an HTTP or HTTPS (secured) connection.

A memory element can be positioned to interact with one or more of the logic element, the interface, or the data analysis server, and record and store historical valuation calculations for future analysis and review. The memory element can be disposed at a location proximate to the drill rig, the logic element, the interface, the data analysis server, or any other suitable location. The memory element can optionally contain a programmable software adapted to erase stored recorded data after a threshold period, e.g., every six months, in order to reduce required storage capacity.

Further, the various measurements between components may be correct but the system may detect that the rig foundation has actually settled and the entire rig must be realigned, such as realigned relative to vertical. The alignment sensor measurements can also be used to help maintain the guide tracks and running gear on the top drive. The system can also be used to measure drifting or “crabbing” of the top drive as it moves throughout the mast. All of this can be used to align the rig components at the initial construction of the rig, at beginning of a new wellbore, or during operation at an existing wellbore.

In a certain embodiment, the system for wellbore operations can further include a stop element adapted to permit a user to terminate drilling operations in the case of an emergency. The stop element can be handled by an operator located at the interface. In this regard, any active drilling operations can be shut down remotely and a service crew can be dispatched to the drill site.

As discussed previously, the alignment sensor can be part of a system for use in subterranean operations. The system can comprise the top drive, the alignment sensor, and the computing system as described above. The alignment sensor can measure and transmit an alignment condition of a rig component and the computing system can receive the sensor data including an alignment condition and determine adjustments to the rig component. As discussed above, the computing system can adjust the rig component based on the alignment condition. For example, the computing system can generate a re-alignment signal to one or more adjustment mechanisms on at least a portion of a derrick. Further, the computing system can actuate at least a portion of the derrick and change the alignment of the first rig component relative to the alignment position. In particular embodiments, the computing system can include an actuator configured to mechanically change the tilt angle of a rig component, such as the derrick, in at least one axis.

Further, a method of operating a system for subterranean operations can include providing a drill rig, establishing a first alignment position, acquiring sensor data regarding the alignment condition of a rig component, and adjusting the rig component to an aligned alignment condition. In certain embodiments, the method can include adjusting the rig component occurs during installation of the rig, during a drilling operation, or continuously throughout the drilling operation. As discussed above, the adjusting can be done remotely. Alternatively, the adjusting can be performed manually and the adjusting can be performed free of a manual level.

Many different aspects and embodiments are possible. Some of those aspects and embodiments are described below. After reading this specification, skilled artisans will appreciate that those aspects and embodiments are illustrative and do not limit the scope of the present invention. Embodiments may be in accordance with any one or more of the embodiments as listed below.

LIST OF EMBODIMENTS

Embodiment 1

A tool for use in subterranean operations, comprising:

a top drive; and

an alignment sensor coupled to the top drive;

wherein the alignment sensor is configured to measure an alignment condition of a first rig component relative to an alignment position.

Embodiment 2

The tool of Embodiment 1, wherein the alignment position includes a first axis, a second axis, or both and the first and second axis are different compared to each other.

Embodiment 3

The tool of Embodiment 2, wherein the first axis is orthogonal to the second axis.

Embodiment 4

The tool of any one of Embodiments 2 and 3, wherein the first axis includes true vertical.

Embodiment 5

The tool of any one of Embodiments 2-4, wherein the first axis has an angle of departure from true vertical that is greater than 0° and less than 90°.

Embodiment 6

The tool of any one of Embodiments 2-4, wherein the second axis includes true horizontal.

Embodiment 7

The tool of any one of Embodiments 2-4, wherein the second axis has an angle of departure from true horizontal that is greater than 0° and less than 90°.

Embodiment 8

The tool of any one of Embodiments 2-7, wherein the first axis, the second axis, or both include an axis of a drill rig component.

Embodiment 9

The tool of Embodiment 8, wherein the drill rig component includes a quill disposed between the top drive and a drill string.

Embodiment 10

The tool of Embodiment 8, wherein the drill rig component includes the top drive, guide tracks disposed on the top drive, running gear disposed on the top drive, or any combination thereof.

Embodiment 11

The tool of Embodiment 8, wherein the drill rig component includes a portion of a drill string.

Embodiment 12

The tool of Embodiment 11, wherein the drill rig component includes a top portion of the drill string.

Embodiment 13

The tool of any one of the preceding Embodiments, wherein the top drive is disposed in a derrick tower.

Embodiment 14

The tool of Embodiment 13, wherein the drill rig component includes a support structure of the derrick tower.

Embodiment 15

The tool of Embodiment 10, wherein the derrick tower is a walking derrick tower.

Embodiment 16

The tool of any one of the preceding Embodiments, wherein measuring an alignment condition includes measuring an angle of departure from the alignment position.

Embodiment 17

The tool of Embodiment 16, wherein the alignment condition includes a normal alignment when the angle of departure from the alignment position is no greater than 5°, no greater than 1°, no greater than 0.5°, or no greater than 0.1°.

Embodiment 18

The tool of Embodiment any one of Embodiments 16 and 17, wherein the alignment condition includes a misalignment when the angle of departure from the alignment position is at least 0.1°, at least 0.5°, at least 1°, or at least 5°.

Embodiment 19

The tool of any one of Embodiments 16 and 18, wherein the angle of departure includes a pitch angle, a roll angle, or a combination thereof.

Embodiment 20

The tool of any one of Embodiments 16-19, wherein the angle of departure is measured at an interval sensitivity of at least 0.1°, at least 0.01°, or at least 0.001°.

Embodiment 21

The tool of any one of the preceding Embodiments, wherein the top drive is coupled to a mast and the alignment sensor is further configured to detect drifting of the top drive as it moves through the mast.

Embodiment 22

The tool of any one of the preceding Embodiments, wherein the alignment sensor includes an inclinometer.

Embodiment 23

The tool of Embodiment 22, wherein the inclinometer includes a microelectromechanical system (MEMS).

Embodiment 24

The tool of Embodiment 22, wherein the inclinometer includes a nanoelectomechanical system (NEMS).

Embodiment 25

The tool of any one of Embodiments 22-24, wherein the inclinometer includes a dual axis inclinometer.

Embodiment 26

The tool of any one of Embodiments 24, wherein the dual axis inclinometer is configured to measure pitch and roll inclination.

Embodiment 27

The tool of Embodiment 22, wherein the inclinometer includes a bubble inclinometer.

Embodiment 28

The tool of any one of the preceding Embodiments, wherein the alignment sensor includes a laser alignment system.

Embodiment 29

The tool of any one of the preceding Embodiments, wherein the alignment sensor is adapted to be monitored in a rig control system.

Embodiment 30

The tool of any one of the preceding Embodiments, wherein the alignment sensor is coupled to a fixed position on the top drive.

Embodiment 31

The tool of any one of the preceding Embodiments, wherein the alignment sensor is integrated into a remote panel on the top drive.

Embodiment 32

The tool of any one of the preceding Embodiments, wherein the alignment sensor is disposed in a fixed position on the top drive.

Embodiment 33

The tool of Embodiment 32, wherein the alignment sensor is adhered to the top drive.

Embodiment 34

The tool of any one of the preceding Embodiments, wherein the alignment condition is configured to be transmitted to a computing system.

Embodiment 35

The tool of Embodiment 34, wherein the computing system is configured to display the alignment condition on a human-machine interface.

Embodiment 36

The tool of Embodiment 35, wherein the human-machine interface is configured to display the alignment condition using models of adjustable sections of a mast, the top drive, a top drive support structure, or an entire rig.

Embodiment 37

The tool of any one of Embodiments 34-36, wherein computing system is configured to adjust the rig component based on the alignment condition.

Embodiment 38

The tool of any one of Embodiments 34-37, wherein computing system is configured to display realignment instructions based on the alignment condition.

Embodiment 39

The tool of any one of the preceding Embodiments, wherein the alignment sensor is configured to generate a signal indicating the alignment condition.

Embodiment 40

The tool of Embodiment 39, wherein the signal includes at least one of a signal indicating an aligned condition and a signal indicating a misaligned condition.

Embodiment 41

The tool of Embodiment 40, wherein the signal indicating the alert condition includes a series of escalating alerts depending on the alignment condition.

Embodiment 42

The tool of any one of Embodiments 39-41, wherein the signal is transmitted within a working environment.

Embodiment 43

The tool of any one of Embodiments 39-41, wherein the signal is transmitted to a remote monitoring environment.

Embodiment 44

A system for use in subterranean operations comprising:

• • a top drive;
  • an alignment sensor coupled to the top drive, the alignment sensor configured to measure and transmit an alignment condition of a first rig component relative to an alignment position; and

a computing system in communication with the alignment sensor, the computing system configured to receive the alignment condition from the alignment sensor and determine adjustments to the rig component based on the alignment condition

Embodiment 45

The system of Embodiment 44, wherein computing system is configured to display the alignment information on a human-machine interface.

Embodiment 46

The system of Embodiment 44, wherein the human-machine interface is configured to display the alignment condition using models of adjustable sections of a mast, the top drive, a top drive support structure, or an entire rig.

Embodiment 47

The system of any one of Embodiments 44-46, wherein computing system is configured to adjust the rig component based on the alignment condition.

Embodiment 48

The system of any one of Embodiments 44-47, wherein the computing system is configured to generate a re-alignment signal to one or more adjustment mechanisms on at least a portion of a derrick.

Embodiment 49

The system of Embodiment 48, wherein the one or more adjustment mechanisms is configured to actuate at least a portion of the derrick and change the alignment of the first rig component relative to the alignment position.

Embodiment 50

The system of any one of Embodiments 48-49, wherein the one or more adjustment mechanisms includes an actuator configured to mechanically change the tilt angle of the derrick in at least one axis.

Embodiment 51

A method of operating a system for subterranean operations comprising:

• • providing a drill rig and establishing a first alignment position, wherein the drill rig includes a top drive and an alignment sensor coupled to the top drive;
  • acquiring an alignment condition of a first rig component relative to an alignment position; and

adjusting the first rig component to change the alignment condition the first rig component relative to the alignment position

Embodiment 52

The method of Embodiment 51, wherein the drill rig includes a walking drill rig.

Embodiment 53

The method of any one of Embodiments 51 and 52, wherein adjusting the first rig component occurs during installation of the rig.

Embodiment 54

The method of any one of Embodiments 51-53, wherein adjusting the first rig component occurs during a drilling operation.

Embodiment 55

The method of any one of Embodiments 54, wherein adjusting the first rig component occurs continuously throughout the drilling operation.

Embodiment 56

The method of any one of Embodiments 51-55, wherein adjusting the first rig component occurs manually.

Embodiment 57

The method of any one of Embodiments 51-55, wherein adjusting the first rig component occurs free of a manual level.

Benefits, other advantages, and solutions to problems have been described above with regard to specific embodiments. However, the benefits, advantages, solutions to problems, and any feature(s) that may cause any benefit, advantage, or solution to occur or become more pronounced are not to be construed as a critical, required, or essential feature of any or all the claims.

After reading the specification, skilled artisans will appreciate that certain features are, for clarity, described herein in the context of separate embodiments, may also be provided in combination in a single embodiment. Conversely, various features that are, for brevity, described in the context of a single embodiment, may also be provided separately or in any subcombination. Further, references to values stated in ranges include each and every value within that range.

The embodiments provide a combination of features, which can be combined in various matters to describe and define a method and system of the embodiments. The description is not intended to set forth a hierarchy of features, but different features that can be combined in one or more manners to define the invention. In the foregoing, reference to specific embodiments and the connection of certain components is illustrative. It will be appreciated that reference to components as being coupled or connected is intended to disclose either direct connected between said components or indirect connection through one or more intervening components as will be appreciated to carry out the methods as discussed herein.

As such, the above-disclosed subject matter is to be considered illustrative, and not restrictive, and the appended claims are intended to cover all such modifications, enhancements, and other embodiments, which fall within the true scope of the present invention. Thus, to the maximum extent allowed by law, the scope of the present invention is to be determined by the broadest permissible interpretation of the following claims and their equivalents, and shall not be restricted or limited by the foregoing detailed description.

The disclosure is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims. In addition, in the foregoing disclosure, various features may be grouped together or described in a single embodiment for the purpose of streamlining the disclosure. This disclosure is not to be interpreted as reflecting an intention that the embodiments herein limit the features provided in the claims, and moreover, any of the features described herein can be combined together to describe the inventive subject matter. Still, inventive subject matter may be directed to less than all features of any of the disclosed embodiments.

Claims

1. A tool for use in subterranean operations, comprising:

a top drive; and

an alignment sensor coupled to the top drive;

wherein the alignment sensor is configured to measure an alignment condition of a first rig component relative to an alignment position.

2. The tool of claim 1, wherein the alignment position includes a first axis, a second axis, or both and the first and second axis are orthogonal compared to each other.

3. The tool of claim 1, wherein measuring an alignment condition includes measuring an angle of departure from the alignment position.

4. The tool of claim 3, wherein the alignment condition includes a normal alignment when the angle of departure from the alignment position is no greater than 5°, no greater than 1°, no greater than 0.5°, or no greater than 0.1°.

5. The tool of claim 3, wherein the alignment condition includes a misalignment when the angle of departure from the alignment position is at least 0.1°, at least 0.5°, at least 1°, or at least 5°.

6. The tool of claim 3, wherein the angle of departure includes a pitch angle, a roll angle, or a combination thereof.

7. The tool of claim 3, wherein the angle of departure is measured at an interval sensitivity of at least 0.1°, at least 0.01°, or at least 0.001°.

8. The tool of claim 1, wherein the top drive is coupled to a mast and the alignment sensor is further configured to detect drifting of the top drive as it moves through the mast.

9. The tool of claim 1, wherein the alignment sensor includes an inclinometer.

10. The tool of claim 9, wherein the inclinometer includes a microelectromechanical system (MEMS) or a nanoelectomechanical system (NEMS).

11. The tool of claim 9, wherein the inclinometer includes a dual axis inclinometer configured to measure pitch and roll inclination.

12. The tool of claim 1, wherein the alignment sensor is adapted to be monitored in a rig control system.

13. The tool of claim 1, wherein the alignment sensor is coupled to a fixed position on the top drive.

14. The tool of claim 13, wherein the alignment sensor is adhered to the top drive.

15. The tool of claim 1, wherein the alignment sensor is integrated into a remote panel on the top drive.

16. The tool of claim 1, wherein the alignment condition is configured to be transmitted to a computing system.

17. The tool of claim 16, wherein the computing system is configured to display the alignment condition on a human-machine interface and display the alignment condition using models of adjustable sections of a mast, the top drive, a top drive support structure, or an entire rig.

18. The tool of claim 16, wherein the computing system is configured to adjust the rig component based on the alignment condition, display realignment instructions based on the alignment condition, or both.

19. A system for use in subterranean operations comprising:

a top drive;

an alignment sensor coupled to the top drive, the alignment sensor configured to measure and transmit an alignment condition of a first rig component relative to an alignment position; and

a computing system in communication with the alignment sensor, the computing system configured to receive the alignment condition from the alignment sensor and determine adjustments to the rig component based on the alignment condition.

20. A method of operating a system for subterranean operations comprising:

providing a drill rig and establishing a first alignment position, wherein the drill rig includes a top drive and an alignment sensor coupled to the top drive;

acquiring an alignment condition of a first rig component relative to an alignment position; and

adjusting the first rig component to change the alignment condition the first rig component relative to the alignment position.