Monitoring motion in a wellbore

Abstract

A rate of penetration ("ROP") of a bottom hole assembly is estimated while drilling a borehole through a subterranean formation. During drilling, topographical features on a sidewall of the borehole are sensed with tactile device having vertically spaced apart surface locations that are sensitive to the topographical features. The topographical features include a localized difference in the material along the sidewall, protrusions in the sidewall, and depressions in the sidewall. Images recorded by the tactile device are used to determine the motion of the drill string and the time span between when the surface locations senses these images is used to estimate the ROP.

Description

Attorney Docket No.: 65NML-511008-WO-2 (0005355.000239)PCT PATENT APPLICATION MONITORING MOTION IN A WELLBOREInventor(s): Radu COMANJohn MACPHERSONCROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority from U.S. Provisional Application Serial No. 63 / 733,245, filed December 12, 2024.BACKGROUND OF THE INVENTION1. Field of Invention

[0002] The present disclosure relates to monitoring the motion of a drilling apparatus within a wellbore or borehole based on monitoring the topography of a wellbore or borehole sidewall, and determining the relative motion of a topographical feature to determine the motion and rate of motion of the drilling apparatus.2. Description of Prior Art

[0003] Drilling systems employed for excavating wellbores in a subterranean formation, and which typically include a drill string made up of a pipe string, a drill bit, a bottom hole assembly (“BHA”) containing tools for measurements and directional steering between the drill bit and the pipe string, and collars and heavy drill pipe connecting the tools and drill bit to the pipe string. The drill string is generally made up of joints of drill pipes, collars and drilling tools connected in series by engaging threads on their opposing ends. The drill bit is rotated by rotating the drill string with either a top drive or a rotary table provided in a drilling rig on surface while drilling mud is circulated within the drill string to remove cuttings the rotating drill bit excavates from the-1- IM -#10773085.1subterranean formation. Other techniques for rotating the drill bit include a mud motor in the BHA that converts mud flowing through the drill string into rotation of the bit.

[0004] The rate of excavating the wellbore is the rate of penetration (“ROP”) of the drill bit through the formation and is an important parameter describing drilling performance and efficiency. The ROP depends on the properties of the formation, and the transmission of power to the drill bit. Power transmission from surface or a downhole motor, and the interaction of the drill bit and the formation, will lead to unintended motion of the BHA and drill string relative to the borehole wall.

[0005] Such motions can result in poor wellbore quality, incorrect trajectory of the wellbore, and incorrect imaging of the adjacent formation by logging while drilling (“LWD”) devices, such as nuclear magnetic resonance (“NMR”), acoustic, and electrical devices. Additionally, some drilling systems are controlled by automated systems that adjust drilling operation by taking operational actions based on sensor feedback, and these systems rely on a good estimate of the ROP as well as good measure of the formation properties and wellbore trajectory. Currently, the ROP is estimated from the vertical motion of the hoist system of the drilling rig deployed on surface. However, this may not reflect the true rate-of-penetration of the drill bit relative to the formation due to compliance of the drill string connecting the surface drilling rig to the drill bit, which can absorb some of the vertical motion of the surface hoist through compression and stretching. The depth of the bit in the wellbore may be estimated from a measure of the drill string, at each connection of a new joint or stand of pipe to the drill string, so long as the same measurement conditions are observed and the temperature of the drill string is known. Between connections, however, the estimate of depth may be severely affected by unintended motions of the drill string, which lead to compression and stretching and errors in the estimate. Integration of a downhole measure of axial motion would help considerably in estimating the depth of the bit in the wellbore between connections. Additionally, other motions of the drill bit and BHA such as torsional motions are attenuated by the drill string and may not be observed on surface. These motions may lead to artifacts in image and measurements of formation properties made by LWD devices. Therefore, current methods of measuring the downhole motion of the drill bit and BHA and the rate of penetration of the drill bit are inadequate, which reduces drilling performance and efficiency and affects the acquisition and processing of LWD data.-2- IM -#10773085.1SUMMARY OF THE INVENTION

[0006] Disclosed herein is an example of a downhole system to detect a movement of a downhole device in a borehole, which includes a downhole device in the borehole, a sensor array in the downhole device, which is configured to detect a topographical feature in a wall of the borehole. The system of this example further includes a drive member to move the sensor array towards the wall of the borehole, a processor configured to obtain a first set of sensor array data at a first time, obtain a second set of sensor array data at a second time, and determine a movement of the downhole device relative to the borehole wall using the first set of sensor array data and the second set of sensor array data. The sensor array is at least a 1 -dimensional array in one example. The processor is optionally configured to cross-correlate the first set of sensor array data and the second set of second sensor array data. In an embodiment, the downhole system further includes a scribe that is selectively projected radially outward into contact with the borehole wall to create a controlled typological feature ahead of the sensor array, the controlled topological feature being a sine wave. The processor is optionally configured to perform an operational action based on the determined movement of the downhole device, or to determine a rate of penetration based on the determined movement of the downhole device, the first time and the second time. In an embodiment, the sensor array contacts the borehole wall, that alternatively includes a first sensor and a second sensor, and the topographical feature is detected by the first sensor at the first time and by the second sensor at the second time, and alternatively the first sensor is at a first location in the sensor array and the second sensor is at a second location in the sensor array, and the movement of the downhole device is determined using the first location and the second location. In an example, the sensor array is a tactile sensor array. In examples, the sensor array is a piezoresistive or piezo electric sensor. In an embodiment, the downhole device includes a body having a longitudinal axis and the sensor array is disposed in a receptacle in an outer surface of the body, and the drive member configured to move the sensor array towards the wall of the borehole includes an electromagnet and an control unit configured to activate the electromagnet to generate a magnetic field, the magnetic field causing the sensor array to move towards the borehole wall and to exit at least partially the receptable.

[0007] Also disclosed is an example of a method to detect a movement of a downhole device in a borehole, which includes conveying a downhole device in the borehole, the downhole device including a sensor array, the sensor array configured to detect a topographical feature in a wall of -3- IM -#10773085.1the borehole. The method of this example also includes driving, using an actuation system, the sensor array towards the wall of the borehole using a driving member, obtaining, using a processor, a first set of sensor array data at a first time and a second set of sensor array data at a second time, determining, using the processor, a movement of the downhole device using the first set of sensor array data and the second set sensor array data. In an alternative, the method further includes cross-correlating, using the processor, the first set of sensor array data and the second set of sensor array data. In another alternative, the method further includes determining, using the processor, a rate of penetration based on the determined movement, the first time, and the second time. In an embodiment, obtaining a first set of sensor array data and a second set of sensor array data includes detecting the topographical feature in the wall of the borehole at the first time with a first sensor in the sensor array and at the second time with a second sensor in the sensor array, and where the first sensor is at a first location in the sensor array and the second sensor is at a second location in the sensor array, and the movement of the downhole device is determined using the first location and the second location. In an alternative, the sensor array is a tactile sensor array and driving the sensor array towards the wall of the borehole includes bringing the tactile sensor array in contact with the wall of the borehole. Optionally, driving the sensor array towards the borehole wall includes activating an electromagnet.

[0008] Another example of a downhole system for use in a borehole is disclosed, which includes a downhole device in the borehole, an electromagnet, a control unit configured to actuate the electromagnet, an interaction device configured to interact with a wall of the borehole, and where the electromagnet moves the interaction device towards the borehole wall when actuated. In one example, the interaction device is a sensor array.-4- IM -#10773085.1BRIEF DESCRIPTION OF DRAWINGS

[0009] Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which:

[0010] FIG. 1 is a side partial sectional view of an example of a drilling system having a drill string with a drill collar.

[0011] FIG. 2 is an axial sectional view of a portion of the drill collar of FIG. 1.

[0012] FIGS. 3 and 3A are side sectional detailed views of an example of the drill collar of FIG.1.

[0013] FIG. 4 is an elevational view of a sensor pad on a blade of the drill collar of FIG. 3.

[0014] FIG. 5 is an elevational view of an example of the sensor pad of FIG. 4 sensing a surface features along a wellbore sidewall.

[0015] FIGS. 6A and 6B are elevational views of examples of markings on a wellbore sidewall created by a scribe on a blade of the drill collar’ of FIG. 3.

[0016] While subject matter is described in connection with embodiments disclosed herein, it will be understood that the scope of the present disclosure is not limited to any particular embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents thereof.-5- IM -#10773085.1DETAILED DESCRIPTION OF INVENTION

[0017] The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes + / - 5% of a cited magnitude. In an embodiment, the term “substantially” includes + / - 5% of a cited magnitude, comparison, or description. In an embodiment, usage of the term “generally” includes + / - 10% of a cited magnitude.

[0018] It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation.

[0019] In FIG. 1 is a side partial sectional view of an example of a downhole system 10, which includes a drilling system 20 shown forming a wellbore 22 into a subterranean formation 24. The wellbore is also referred to herein as borehole. The drilling system 20 includes a drill string 26 shown within wellbore 22, and which is being rotated by a top drive 28 supported within a derrick 30 mounted on surface S over the wellbore 22. Optionally, rotation of drill string 26 can be from a rotary table (not shown) on the derrick floor. Drill string 26 is made up of a pipe string 32, which includes a number of drill pipe sections threaded together end-to-end. On a lower end of pipe string 32 is a drill bit 34 for excavating through the formation 24. An annulus 36 is between the pipe string 32 and sidewalls of the wellbore 22, also referred to herein as a wall of the borehole or borehole wall. A stabilizer section 38 is included on the pipe string 32 shown having an increased diameter that projects radially outward into the annulus 36. In an alternative, stabilizer section 38 and drill bit 34 are included in a bottom hole assembly (BHA) 39 on the drill string 26. The BHA 39 is connected to the lower end of the pipe string 32. Outside the wellbore 22 the downhole system 10 includes a surface controller 40 in communication, via a communication means 42, with the-6- IM -#10773085.1drilling system 20 and its components, including the stabilizer section 38. The communication between the surface controller includes wellbore telemetry 41, such as mud pulse telemetry, wired pipe, electromagnetic (EM) telemetry, or acoustic telemetry. Examples of communication means 42 from a telemetry receiver (not shown) to surface controller 40 includes wireless, fiber optic, and hardwired. In an embodiment the surface controller 40 is a processor, and optionally is in communication with locations remote to the downhole system 10 via state-of-the-art communication links, such as the Internet. The BHA 39 includes an electric power generator 37 to provide electric power to the electronic components of the BHA. A blowout preventer 44 is also included in the example drilling system 20.

[0020] FIG. 2 is an axial sectional view of a portion of the stabilizer section 38 and taken along lines 2-2 of FIG. 1. Shown in this example is that stabilizer section 38 includes a housing 45 that circumscribes drill string 26, and where drill string 26 is rotatable with respect to the housing 45. The portion of the drill string that is circumscribed by the stabilizer section 38 is also referred to herein as drive shaft 27. Described below in more detail is that housing 45 is rotationally static with sidewall 51 of wellbore 22 while drill string 26 rotates within wellbore 22. The drill string 26 rotates the drive shaft 27 and transmits torque (from the top drive 28) to the drill bit 34 at the lower end of the BHA while housing 45 is not rotated by the drive shaft. That is the housing 45 does not rotate with the rotated drill string 26 or can rotate independently of the drill string, respectively. In alternatives, housing 45 rotates with respect to sidewall 51 at a rate less than that of drill string 26. An axial bore 46 extends through stabilizer section 38 and through the drive shaft 27 and along longitudinal axis A38 of the stabilizer section 38. In examples, drilling fluid used in forming wellbore 22 (FIG. 1) flows downward through the axial bore 46 where it exits at nozzles in drill bit 34 and flows back uphole within annulus 36. On an outer surface of stabilizer section 38 and an outer surface of housing 45 are blades 481-3 which as described in more detail below, extend along an axial length and along longitudinal axis A38 of stabilizer section 38 and project radially outward from the outer surface of stabilizer section 38 and perpendicular to the longitudinal axis A38. In the example of FIG. 2 three blades 48i, 482, and 483 are mounted onto stabilizer section 38; embodiments exist in which more than or less than three blades a e included with the stabilizer section 38. In the example shown, on each of the blades 481-3 are sensing units 501-3, which as explained in more detail below are selectively in contact with a side wall 51 of wellbore 22 and provide information about a rate of penetration of the drill bit 34 (FIG. 1) and of the drill string 26-7- IM -#10773085.1through the formation 24 based on sensing and tracking a topographical feature on sidewall 51. The sensing unit(s) 501-3 are also referred to herein as sensor device(s). An example of a typographical feature is something on or along the sidewall 51 that is perceptible, such as with sensory perception, including but not limited to touch or tactile as well as visual or optical. One type of topographical feature is where there is a change or a localized difference in or on the surface of the sidewall 51, such as from the presence of a mineral, a sedimentary structure, mud cake, or a deposit from a material different from material around the deposit. Additional types of topographical features include a depression or protrusion at a localized position on the sidewall 51, such as a drilling mark, a crack, a joint, a fissure, a breakout, or a washout. In an example the stabilizer section 38, with the blades 481-3 in contact with the sidewall 51, operates as a stabilizer to stabilize drill string 26 within wellbore 22. In an example the stabilizer is a low-motion stabilizer, which rotates at a rate that is less than the rotation rate of the drill string. The location of the sensing units 501-3 in blades 481-3 of a stabilizer section 38 allows placing the sensing unit close to the borehole wall 51. In an alternative embodiment the stabilizer section 38 is fixedly connected to the drill string 26 or is part of the drill string, as shown in FIG. 2A. In this embodiment the sensing unit 50 and the sensor pad 64 rotates with the drill string 26 and describes a spiraled line along the wall of the borehole.

[0021] Referring now to FIG. 3, shown in a side sectional view is an example of the stabilizer section 38 of FIG. 2. Blade 48 represents an embodiment of each of blades 481-3 of FIG. 2, and sensing unit 50 represents an embodiment of each of sensing units 501-3 of FIG. 2. An actuation system 52 and a pad assembly 54 are shown included with the sensing unit 50. The pad assembly 54 is also referred to herein as sensor assembly. A receptacle 55 is formed along the outer surface of a portion of blade 48 in housing 45 that is configured to receive sensing unit 50. Actuation system 52 selectively urges the pad assembly 54 from the receptacle 55 towards the sidewall 51 and eventually into contact with the sidewall 51. Included with or connected to the actuation system 52 is a control unit 110 power supply 56 for energizing a magnetic field source 58 to deploy the pad assembly 54 from the receptacle 55. Included in pad assembly 54 is a magnet 60, examples of which include a permanent magnet, an electromagnet, and combinations. In this example, magnetic field source 58 is illustrated as an electromagnet. The magnet 60 is housed within the pad assembly 54 (which serves as a housing or support structure for the magnet 60) and a sensor pad 64 is shown provided on a surface of the pad assembly 54 that is urged into contact with-8- IM -#10773085.1sidewall 51. In the example of FIG. 3, the blade 48 with receptacle 55 serves as a housing for the sensing unit 50, and the stabilizer section 38 is referred to as a downhole tool and may be part of the BHA 39.

[0022] Schematically shown within blade 48 is a docking system 66 for drawing pad assembly 54 back into receptacle 55 and retaining pad assembly 54 within receptacle 55 as designated. In an alternative, the docking system 66 includes a permanent magnet which exerts an attracting magnetic force onto the magnet 60 within the pad assembly 54. The magnetic force exerted by the docking system 66 is less than a magnetic force generated by the magnetic field source 58, so that when the magnetic field source 58 is energized, the attracting magnetic force from the docking system 66 onto the magnet 60 is overcome by the repelling magnetic force from magnetic field source 58 to deploy the pad assembly 54 radially outward from the blade 48. In this example, suspending operation of the magnetic field source 58 eliminates the repelling magnetic force and allows for the magnetic force exerted by the docking system 66 to retract the pad assembly 54 back into the receptacle 55. In one more embodiment the magnetic field source 58 performs both actions, providing the repelling magnetic force required to drive the pad assembly against the sidewall 51 and providing the attracting magnetic force required to retaining the pad assembly. To achieve both actions the actuation system 52 controls the magnetic field source in two modes: repelling and attracting depending on whether the pad assembly is to exit the receptacle or to move back into the receptacle. In a non-limiting example of use, a rate of axial displacement of the stabilizer section 38 within the wellbore 22 and along a longitudinal axis of the wellbore is estimated by engaging the sensor pad 64 against the sidewall 51 at a first time t\ for a short first measurement time interval?miand engaging the sensor pad 64 against the sidewall 51 at a second time t2 for a short second measurement time interval rm2. The measurement time may be smaller than 0.5 s, smaller than 1 s, smaller than 5 s, or smaller than 10 s. In one embodiment the two first and second measurement time intervals tmiand / m2 during which signals are obtained are substantially similar. In an alternative embodiment tmiand / m2 differ from each other. There is a time interval tpbetween the two measurement time intervals in which the drill string 26 with the stabilizer section 38 progresses deeper into the wellbore 22. Within the time interval tpthe sensor pad 64 is optionally retracted back into the receptacle 55 to minimize wear. The time interval tpmay be smaller than 2 s, smaller than 5 s, smaller than 10 s, smaller than 30 s, smaller than 1 min, or smaller than 5 min. The longitudinal axis of the wellbore is parallel to axis A38. In this example,-9- IM -#10773085.1the sensor pad 64 is responsive to and senses topographical features on the sidewall 51 by tactile interaction with the sidewall 51. Described below are examples in which the sensor pad 64 senses these topographical features at multiple locations along its outer facing surface. By recording responsive signals from the interaction of the pad 64 with the sidewall 51 and cross-correlating the signals, taken at different times (first time and second time) and different locations along the axis A38, a distance d is obtained, which when divided by the designated period of time between the first time and the second time, at which these two signals were obtained (second time - first time), a rate of penetration ROP of the stabilizer section 38, and also the drill bit 34 and the drill string 26 is obtained. An example of a sensor pad 64 in accordance with the present disclosure is obtainable from Tekscan at https: / / www.tekscan.com / tactile-pressure-sensor-solutions. Optionally, any motion or movement and / or rate of motion or rate of movement of the stabilizer section within a wellbore is estimated using the system and methods described herein, such as but not limited to, upward movement, downward movement, rotational movement, torsional movement, and oscillatory movement. Use of the sensing unit 50 is not limited to drilling systems, but includes any device or system disposed within a wellbore, such as completion strings, wireline tools, coiled tubing strings, etc. Based on either the distance d or the rate of penetration ROP an operational action is performed, such as one of a geo-steering action (e.g. automatic adjustment of a drilling direction), formation evaluation data analysis or correction (e.g. image generation), data processing, and a downhole log generation.

[0023] A marking unit 68 is shown within blade 48 of FIG. 3 and at a location along axis A38 downhole of the sensing system 50. Included with marking unit 68 is a scribe 70 shown having a pointed end directed radially outward from the stabilizer section 38. An actuator 72 (e.g. hydraulic, electric, or magnetic actuator) is coupled with the scribe 70, which selectively urges the scribe 70 radially outward and into contact with sidewall 51. As described in more detail below, the scribe 70 engages the sidewall 51 to create impressions or other markings along sidewall 51, the presence of which are detected by the sensor pad 64, and provide additional resolution for estimating the rate of penetration. The sensor pad is also referred to herein as a sensor array. Similar to the sensing unit 50, all embodiments of the scribe 70 as described herein are usable with all downhole devices and all types of movement with respect to the sidewall 51 (borehole wall). An optional measurement wheel 74 is schematically shown included in blade 48, the wheel 48 is selectively urged radially outward into contact with sidewall 51, and resulting rotations of the wheel 74 are-10- IM -#10773085.1monitored to estimate displacement along wellbore 22. Evaluating measurements obtained by the wheel 74 provides a comparative analysis from using the sensor pad 64 to detect topographical features on the sidewall 51.

[0024] Still referring to FIG. 3, further optional components are included within the stabilizer section 38 for operation of the sensing unit 50, docking system 66, marking unit 68, and for communication with the controller 40 (FIG. 1). These additional components include a wireless power receiver 76, control and processing unit 80, wireless power transmitter 82, a contact and proximity sensor 84, a power unit 86, a communication unit 88, and a measurement unit 90. In examples, the wireless power receiver 76 provides a way of wirelessly receiving electrical power from the drill string for energizing components within the stabilizer section 38. The power generator 37 (FIG. 1) is in the drill string 26, or respectively in the BHA 39. The stabilizer section 38 rotates relative to the drill string 26. Consequently, power from the drill string 26 is to be transferred to the stabilizer section 38 wirelessly. The wireless communication unit 78 optionally provides a way of communication with other portions of the BHA 39 and the drill string 26 as well as the controller 40 on surface S through wellbore telemetry 41 and communication means 42 (FIG. 1). In an example, the contact proximity sensor 84 is disposed proximate or adjacent to an outer radial portion of the blade 48, and is useful to identify the radial distance from outer surface of the blade 48 to sidewall 51. Proximity sensors are well known in the prior art and may for example be an acoustic proximity sensor, such as an acoustic caliper, a mechanical sensor, a resistive sensor, a pressure sensor, or an optical sensor. Wireless power receiver 76 selectively provides electrical power to the components within the stabilizer section 38. Wireless power receiver 76 supplies power to wireless power transmitter 82, which wirelessly transmits power to the components of the sensing unit 50. In an alternative embodiment wireless power receiver 76 and wireless power transmitter 82 are combined in one wireless power supply. In an alternative embodiment a battery 86 is or an energy harvesting unit (not shown) within the housing 45 of stabilizer section 38 is used to power the sensing unit 50. In an alternative, communication unit 78 is a hard-wired device for communicating with the surface S or other parts of the drill string 26. The example measurement unit 90 includes logics for controlling when to move the pad assembly 54, when to measure with the pad assembly 54, and when to energize the actuation system 52.

[0025] Shown in FIG. 4 is a plan view of an example of the sensor pad 64 mounted on the base 62 (FIG. 3) and within the receptacle 55. Provided on these sensor pads 64 is an array 92 of points -11- IM -#10773085.194x,z, which are discrete locations along a substantial portion of the surface of the sensor pad 64, embodiments exist in which each of the points 94x,zon the sensor pad 64 have tactile sensitivity, and when in contact with a surface are responsive to a topographical feature on the surface. The surface may be the sidewall 51 of the wellbore 22. Optionally, the points 94x,zinclude sensors (not shown) making array 92 being a sensor array including a plurality of sensors. The plurality of sensors are one or more of force-sensitive resistors, piezoelectric sensors, capacitive pressure sensors, flexible or soft sensors. In this example, the principle of sensing includes piezoresistive, piezoelectric, ultrasonic, optical, capacitive, resistive, magnetic, inductive, and combinations. In a non-limiting example of operation, these sensors measure formation properties, such as but not limited to formation resistivity, formation dielectric constant, magnetic susceptibility, magnetic field intensity and orientation. In the example of FIG. 4, the array 92 is shown having up to “X” columns (z.e., 94i,i to 94x,i) and up to “Z” rows (z.e., 94i,i to 94i,z) and having up to (X)*(Z) points 94. Embodiments exist in which a length and width of the sensor pad 64 and array 92 extend up to about a length and width of a blade 48 on which the sensor pad 64 is mounted. In the example of FIG. 4, the surface of the sensor pad 64 generally follows a straight line in the axial direction parallel to axis A38 and follows a curved line along the circumferential direction perpendicular to axis A38. In examples, the curvature of the surface of the sensor pad 64 is along a radius substantially the same as a radius of wellbore 22. In other words, the surface of sensor pad 64 forms a portion of a cylindrical surface. Example, distances between adjacent one of the points 94 of FIG. 4 range from 0.5 millimeters, 0.75 millimeters, 1 millimeter, 1.2 millimeters, and up to in excess of 5 millimeters. Alternatives exist in which there are multiple arrays 92 (not shown) on the same or different sensor pads 64, on different parts of the blade 48, or different parts of the drilling system 20.

[0026] Referring now to FIG. 5, shown in an elevational view is an example of the sensor pad 64 moving downward in the direction of arrow A and along the surface of sidewall 51. Downwards in this application refers to downhole, or deeper into the subterranean formation. Downhole is the opposite direction to uphole, which refers to upward and a direction towards the earth surface or shallower in the subterranean formation. A group 96 of surface features 981-4 on the sidewall 51, are shown behind the sensor pad 64 and at relative points 94 on the sensor pad 64 when being sensed by the plurality of sensors in the sensor pad. In a non-limiting example, when a point or points or sensors 94 on the pad 64 sense a surface feature 98 on the sidewall 51, a signal (not-12- IM -#10773085.1shown) is generated by the sensor pad 64, which is transmitted to one or more of communication unit 88, control and processing unit 80, wireless communication unit 78, and / or controller 40 via communication means 42. In this example, the signal includes information representing a relative time when the respective surface feature 98 (such as a topographical feature) was sensed by the specific sensor in the sensor pad, and optionally further includes information about a size, shape, and / or configuration of the surface feature 98. In examples in which multiple points 94 sense a surface feature 98 simultaneously, such as if the surface feature 98 has an area exceeding that of a single one of the points 94, the signal includes information indicating that the surface feature 98 was sensed by these points 94. For the purposes of discussion herein, a location on the pad 64 refers to a particular point 94 or points 94 on the pad 64 where a surface feature 98 is being sensed. In a non-limiting example, cross-correlation is performed between sensor array data sets taken at different moments in time. Cross -correlation is a measure of similarity between two signals or data sets as a function of the displacement of one relative to the other. When applied to two-dimensional (2D) data arrays, it helps identify the degree to which one data set matches or is shifted relative to another data set detected at a different time. Optionally, the cross-correlation is based on sensing one or more of the other surface features 982-4. For the purposes of illustration, points 94m-n, o-pidentify the location on the sensor pad 64 the surface feature 981is sensed at an earlier point in time (first time) and points 94m-n,q-ridentify the location on the sensor pad 64 the surface feature 981is sensed at a later point in time (second time). A distance d between these locations, i.e., between points 94m-n, o-pand points 94m-n,q-ris known. The distance d is the displacement of the BHA 39, or of the stabilizer section 38, or of the drill string 26, or of the drill bit during the time interval between the two sensed data sets. The data sets can also be considered images or image data (2-D image data). As shown in FIG. 5 the displacement is an axial displacement along the longitudinal axis of the wellbore 22 (FIG. 1) or along longitudinal axis A38 (FIGS 2 and 2A). By estimating a rate of axial displacement determines a ROP of the BHA 39, stabilizer section 38, drill string 26 and drill bit 34. It is within the capabilities of those skilled in the art to perform a cross-correlation procedure comparing multiple arrays of data or data sets. Examples of estimating upward, downward, and / or axial oscillatory movement include evaluating a distance between points 94m-n, o-p and points 94m-n,q-r. Examples of estimating simple or oscillatory rotational movement include evaluating a distance between points that are at different azimuthal locations along the array 92 (e.g., between point 94i,i and point 94x,i). Azimuthal locations refer to different-13- IM -#10773085.1locations along the circumference of the borehole. To detect a displacement along an axial displacement, or along a circumferential displacement a 1-D sensor pad is sufficient. However, the embodiment described in this application uses a 2-D sensor array 92 or 2-D sensor pad 64. The detected signal is a data set that includes sensed signal provided by each of the plurality of sensors in the sensor array recorded at a specific time (e.g. first time or second time). While the time is progressing the stabilizer section 38 moves with the BHA 39 or the drill string 26 relative to the borehole or the wall of the borehole. The data set recorded at a second time (later than the first time) will be different to the data set recorded at a first time in that a surface feature recorded at the first time at a first location or at a first sensor in the sensor pad will be recorded at a second time at a second location or a second sensor in the sensor pad. The distance between the sensors in the sensor array is known and is well defined by the coordinates x and z. Recording the data set sensed by the plurality of sensors in the sensor pad 64 at locations 94x,zat the first time (ft) to provide a data set at the first time and recording the data set sensed by the plurality of sensors in the sensor pad 64 at different locations 94x,zat the second time (ft) to provide a data set at the second time is unambiguously defined by the distance the sensor pad 64 on the stabilizer section 38 is moved with the time interval (ft - ft). Different to FIG. 4, the view in FIG. 5 is from the center of the drill string through the sensor pad 64 onto the sidewall 51. The view in FIG. 4 is from the sidewall 51 onto the sensor pad 64. Two data sets acquired at different points in time will be cross-correlated. A correlation coefficient will be calculated. A maximum in the correlation coefficient will indicate when the two data sets best correlate. The shift of the two data sets relative to each other that corresponds with the maximum of the correlation coefficient defines the distance the stabilizer section 38, the drill string 26 and the drill bit 34 moved within the time interval between the different points in time when the two data sets where recorded. The cross correlation can be performed for a 1 -dimensional data set or for a 2-dimensional data set.

[0027] FIG. 6A is an elevational view of an example in which the scribe 70 of the marking unit 68 is mounted onto an oscillator 100 which reciprocates the scribe 70 circumferentially about the stabilizer section 38 (FIG. 3). The reciprocating motion creates a trace 102 along the sidewall 51 having a sine-wave-like configuration. In this example, the oscillations of the scribe 70 are at a known frequency, and are detected by the pad assembly 54 when deployed from the receptacle 55 (FIG. 3) into contact with sidewall 51. When encountering the topographical feature generated by the trace 102, the sensor pad 64 generates responsive signals (data sets). Frequency as measured-14- IM -#10773085.1by the pad 64, which is referred to as an instantaneous frequency of the sine wave form, is a function of the rate of penetration of the drill bit 34 (FIG. 1). This frequency can be determined from this single wave form of the trace 102 using a Hilbert transform to generate an analytic signal. The Hilbert Transform of a first signal is a second signal, and the combination of the two signals is termed the analytic signal, which can be used to directly derive the phase of the signal, and the time derivative of the phase yields the instantaneous frequency. Alternatively, as shown in FIG.6B, a pair of scribes 70A1,2are shown mounted on oscillators 100A1,2which create a pair of traces 102A1,2formed along the sidewall 51. In this case, if the scribes are offset by 90 degrees then the frequency is obtainable directly from analyzing these traces 102A1,2. For the purposes of discussion herein, trace 102 and traces 102A1,2are referred to as controlled topographical features.

[0028] In a non-limiting example of operation, a pad assembly 54 of FIG. 3 is selectively deployed from its corresponding blade 48 and into contact with the sidewall 51 while the wellbore 22 of FIG. 1 is being formed. As the drill string 26 and stabilizer section 38 are moved axially along axis A38 within the wellbore 22, the pad 64 maintains contact with the sidewall 51 and the various points 94 of FIG. 4 on the array 92 are responsive to the topographical features along sidewall 51. The pad assembly 54 is deployed from the receptacle 55 for a period of time while the output signals from the various points or sensors 94 are collected. Examples of the collection include transmitting data signals from each of the points or sensors 94 to communication unit 88, measurement unit 90, control and processing unit 80, wireless communication unit 78, or another device or component which receives, stores, and / or processes data. The data or data sets obtained from the pad 64 is analyzed, such as by cross-correlation and where two data sets recorded at different positions along an axial line are correlated, a distance the stabilizer section moved between the particular one of the recorded data sets from the sensor array 92 is provided. Using the moved distance and dividing it by the time elapsed between recording the two data sets gives a rate of penetration (ROP) the stabilizer section 38, the BHA 39, the drill string 26 and the drill bit 34 penetrated into the subterranean formation 24. Optionally, these topographical features or surface irregularities are created by activating the scribe 70 as discussed above, and further optionally, the measurement wheel 74 is engaged over the period of time while the pad assembly 54 is deployed, and the distances monitored by the measurement wheel 70 and the pad assembly 54 are compared with one another for Quality control purposes. In an alternative, magnetic source 58 is between a pair of permanent magnets which have an attracting force with one another that is-15- IM -#10773085.1overcome by activating the magnetic source 58. One permanent magnet in this configuration is fixed to the housing 45 and the other permanent magnet is included in the pad assembly 54.

[0029] Advantages of the present disclosure include using a magnetic force to deploy the sensor device reduces wear. The usage of a magnetic force allows the sensor assembly (pad assembly 54) to automatically adjusts the changes in distance to the sidewall 51 to maintain continuous contact without using unnecessary force to press the sensor against the sidewall 51. The magnetic force is not as stiff as the force of a stiff mechanical mechanism which could be used alternatively. The magnetic force has a kind of inherent spring functionality which allows the sensor pad to follow variations in the contour of the sidewall 51 by slight radial movement, without damaging the sensor assembly 54. In addition to reducing wear, a further advantage of pressing pad 64 against sidewall 51 with an amount force adequate to maintain contact between sensor pad 64 and sidewall 51 and less than a force that disturbs or alters the topographical features allows the subsequent sensing of the feature with a different location on the sensor pad 64 or on a different sensor array 92. That is the magnetic force is good to allow the sensor pad to follow the contour in radial direction (FIG.3) of the sidewall while sliding along the sidewall 51. In an example, if topographical features sensed at a first time are not sensed at a second time, later than the first time, or subsequently in time, such as by points or sensors 94 on a different location of pad 64, a force pressing sensor pad 64 against sidewall 51 is reduced so that the pad 64 maintains contact with sidewall 51 without disturbing the topographical features. The present disclosure also eliminates the need for high pressure sealing, the magnetic deployment system has no moving parts, and because the magnets are enclosed and are protected from drilling mud, the magnets have adequate structural integrity to withstand downhole forces and temperature. In the case of a loss of power, the magnetic docking is a fail-safe operation for function that returns the sensor pad to the receptacle. Further advantages of the embodiment with an electromagnet is the intermittent and controlled contact of the sensor assembly to the sidewall which further reduces wear and extends its operational life. Moreover, the activation time of the magnetic force is very short, the magnetic force can be turned off or the polarity can be inverted, providing better operational control during retrieval or repositioning.

[0030] The system and method disclosed herein provides drilling optimization and formation evaluation during borehole drilling, and in an alternative includes a bottom hole assembly (BHA) with a component having a receptacle with an opening that faces the borehole wall and a first -16- IM -#10773085.1magnet in proximity of this receptacle, a sensor assembly that is positioned in the receptacle comprising a sensor and a second magnet, wherein the first and second magnets can generate a repulsive force that moves the sensor assembly to make contact to the borehole wall, where the sensor is providing real-time data to optimize the drilling process and evaluate formation properties. The component has contact with the borehole wall, and in alternatives is a stabilizer. The component optionally rotates at a slower speed compared to an attached drill string, and optionally is a slow rotating stabilizer and has one or more blades. In this example, a sensor assembly is placed in two or more of the blades. In embodiments, the sensor assembly is a sensor array, that alternatively includes a (wireless) power unit and a wireless communication unit. In one example, the sensor array is configured to capture high-resolution images or data sets that distinctly reveal the topographical features of the borehole wall, and optionally measures formation properties, such as but not limited to magnetic properties. In examples, the effect of the topographical features is either predominant or can be extracted from the measured data. Alternatively, the sensor array is configured to capture high-resolution images of topographical features on the borehole wall with a spatial resolution capable of distinguishing surface features; example lateral extents are less than about 5mm, 2 mm, 1 mm, or 0.5 mm. Sensing principles include piezoresistive, piezoelectric, ultrasonic, optical, capacitive, resistive, magnetic, inductive, and combinations thereof, and in an embodiment is a tactile sensor array or a soft (compressible) tactile sensor array. In an embodiment, the surface of the sensor assembly contacting the borehole wall has a similar curvature as the expected curvature of the borehole wall defined by the radius of the borehole. In examples, the surface of the receptacle or the surface of the sensor device is rough, allowing the drilling fluid to surround the sensor device from all sides while, thereby reducing the likelihood of sticking between the sensor device and the receptacle while movement of the pad assembly in the receptacle when pressing or pushing the pad assembly against the borehole wall. In a non-limiting example of operation, the BHA is in motion while the sensor assembly is pushed against the borehole wall, and optionally a body of the component (such as housing 45) is made of non-magnetic material. The sensor assembly is alternatively configured to measure two images or data sets at two moments in time (first time, second time) that optionally superpose each other at least partially. An algorithm is optionally used to process the two images to obtain tool motion of the BHA between the two moments in time, such as but not limited to cross-correlation; in this example axial motion is extracted from the computed tool motion, and-17- IM -#10773085.1further optionally a rate of penetration (ROP) is computed from the axial motion using the time difference between the two moments in time. Example of the system further include an additional component (such as scribe 70 (FIG. 3)) configured to scratch or punch the formation to create artificial a topographic feature(s) when the recorded images lack sufficient natural topographical features or when the borehole wall is not comprising sufficient natural topographical features. The ROP is optionally computed downhole while drilling (real-time application), and the ROP is in an embodiment used downhole for operational actions such as one of steering decisions, data acquisition, or data processing. In examples, the ROP and / or data that has used the ROP is transmitted to the surface using borehole telemetry. The sensor assembly optionally remains in contact with the borehole wall for an extended period, during which data is measured at intervals over time. In an embodiment, the sensor assembly is configured for short, intermittent contact with the borehole wall, such that contact is made only briefly to perform a measurement before the device is retracted. Drilling dynamics sensors are optionally included on the system, which measure drilling dynamics and are used to control whether the measurement by the first sensor should be performed or not; examples of which include proximity or contact sensors. In another example, a securing mechanism is included that is configured to prevent the sensor assembly from exiting the receptacle, while allowing limited movement within the receptacle, where the sensor pad optionally measures a formation property and the formation property is alternatively one of formation pressure, formation dielectric constant, magnetic field intensity and orientation, formation hardness, formation temperature, formation texture, and formation NMR porosity. Example sensors in the sensor array in the sensor device include force- sensitive resistors, piezoelectric sensors, capacitive pressure sensors, flexible or soft sensors. In one example of the system one magnet is an electromagnet, and in alternatives is external to the sensor assembly. The strength of the electromagnet is optionally controlled to ensure optimal contact pressure. In alternatives, the magnet with the sensor assembly is a permanent magnet, and magnetic material outside the sensor assembly is used to ensure magnetic docking of the sensor assembly in the receptacle.

[0031] In FIG. 3A is a detailed portion of the string 26 of FIG. 3 schematically illustrating the sensing unit 50, comprising a data acquisition unit 104, a wireless communication unit 106, a wireless power receiver 108, a magnet 60, and a sensor pad 64. Data acquisition unit 104 can be a processor. In an embodiment sensing unit 50 is a module defined by a module housing 112. This-18- IM -#10773085.1is, the sensing unit 50 is a self-contained unit with no cable connections through module housing 112. Power for the operation of the electronic components of the sensing unit 50 within the module housing 112 is transmitted wirelessly from a wireless power transmitter 82 in the drill string and / or the housing 45 (FIG. 2) to the wireless power receiver 108, e.g. by electromagnet induction. Communication from the drill string 26 is transmitted from the wireless communication unit 78 in the drill string and / or the housing 45 to the wireless communication unit 106 in the sensing unit. The communication from the sensing unit 50 to the drill string 26 is provided from the wireless communication unit 106 in the sensing unit 50 to the wireless communication unit 78 in the drill string and / or the housing 45. In case the housing 45 rotates relative to the drill string 26, the power and communication from the drill string 26 to the housing 45 and vice versa is performed wirelessly, here represented by a wireless power receiver 76 and the wireless communication unit 78. The sensor pad 64 is integrated in a housing wall of the module housing 112 of the sensor unit 50, also referred to herein as a base 62. In an example, the wireless communication unit 106 receives data and / or signals from the data acquisition unit 104 and transmits the data / signals to wireless communication unit 78 either for being processed downhole by the processing unit 80 or for transmission uphole, such as via wellbore telemetry 41 (FIG. 1). Further in this example, data acquisition unit 104 and wireless communication unit 106 are powered by wireless power receiver 108, which in turn is powered at least in part by energy received from wireless power transmitter 82. Alternatively, the power supply can be a battery (not shown). Also shown is an arrow illustrating radial directions of force F for urging sensor pad 64 into and from contact with sidewall 51 of the wellbore. The urging of the sensor pad 64 into contact with the sidewall 51 is driven by a magnetic drive member, such as a magnetic field source 58 (e.g. an electromagnet). The magnetic field source 58 in the actuation system 52 is activated by a control unit 110. In alternatives, actuation system 52 is powered by the wireless power transmitter 82, which optionally provides the power to the actuation system via a power cable. Alternatively, actuation system, 52 has a separate power supply as shown in FIG. 3. Actuating the magnetic field source 58 creates a repelling force F. As shown in FIG. 3, a docking system 66 ensures that the sensing unit 50 is securely parked within the receptacle 55 when the magnetic field source 58 is deactivated. A securing mechanism 63 limits the movement of the sensing unit 50 while exiting the receptacle 55. The surface of the receptable 55 optionally includes a surface feature 65 that increases the roughness of the surface to allow drilling fluid to surround the sensing unit 50 to reduce the-19- IM -#10773085.1likelihood of sticking. Examples of the surface feature 65 include grooves, holes, pins, or any kind of arbitrary roughness increasing structure.

[0032] The present invention described herein, therefore, is well adapted to carry out the objectives and attain the ends and advantages mentioned, as well as others inherent therein. While one or more embodiments have been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. For example, in alternatives, the sensor array 92 is responsive to signals that are acoustic, optical, magnetic, resistive, electromagnetic, and in combinations. These are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.-20- IM -#10773085.1

Claims

CLAIMSWhat is claimed is.

1. A downhole system to detect a movement of a downhole device in a borehole, the system comprising:a downhole device in the borehole;a sensor array in the downhole device, the sensor array configured to detect a topographical feature in a wall of the borehole;a drive member to move the sensor array towards the wall of the borehole;a processor configured to:obtain a first set of sensor array data at a first time;obtain a second set of sensor array data at a second time;determine a movement of the downhole device relative to the borehole wall using the first set of sensor array data and the second set of sensor array data.

2. The downhole system of claim 1, wherein the sensor array is at least a 2-dimensional array.

3. The downhole system of claim 1, wherein the processor is configured to cross-correlate the first set of sensor array data and the second set of second sensor array data.

4. The downhole system of claim 1, wherein the system further comprises a scribe that is selectively projected radially outward, so that when in contact with the borehole wall a controlled typological feature is formed on the borehole wall in a path of the sensor array, the controlled topological feature comprising a sine wave.

5. The downhole system of claim 1, wherein the processor is further configured to perform an operational action based on the determined movement of the downhole device.

6. The downhole system of claim 1, wherein the processor is further configured to determine a rate of penetration based on the determined movement of the downhole device, the first time, and the second time.

7. The downhole system of claim 1, wherein the sensor array contacts the borehole wall.-21- IM-#10773085.

18. The downhole system of claim 7, wherein the sensor array includes a first sensor and a second sensor, and the topographical feature is detected by the first sensor at the first time and by the second sensor at the second time.

9. The downhole system of claim 8, wherein the first sensor is at a first location in the sensor array and the second sensor is at a second location in the sensor array, and the movement of the downhole device is determined using the first location and the second location.

10. The downhole system of claim 1, wherein the sensor array is a tactile sensor array.

11. The downhole system of claim 7, wherein the sensor array is a piezoresistive or piezo electric sensor.

12. The downhole system of claim 1, wherein the downhole device includes a body having a longitudinal axis and the sensor array is disposed in a receptacle in an outer surface of the body, and the drive member to move the sensor array towards the wall of the borehole includes an electromagnet and a control unit configured to activate the electromagnet to generate a magnetic field, the magnetic field causing the sensor array to move towards the borehole wall and to exit at least partially the receptable.

13. A method to detect a movement of a downhole device in a borehole, the method comprising:conveying a downhole device in the borehole, the downhole device including a sensor array, the sensor array configured to detect a topographical feature in a wall of the borehole;driving, using an actuation system, the sensor array towards the wall of the borehole using a driving member;obtaining, using a processor, a first set of sensor array data at a first time and a second set of sensor array data at a second time;determining, using the processor, a movement of the downhole device using the first set of sensor array data and the second set sensor array data.

14. The method of claim 13, further including cross-correlating, using the processor, the first set of sensor array data and the second set of sensor array data.-22- IM-#10773085.

115. The method of claim 1, further including determining, using the processor, a rate of penetration based on the determined movement, the first time, and the second time.

16. The method of claim 13, wherein obtaining a first set of sensor array data and a second set of sensor array data includes detecting the topographical feature in the wall of the borehole at the first time with a first sensor in the sensor array and at the second time with a second sensor in the sensor array, and wherein the first sensor is at a first location in the sensor array and the second sensor is at a second location in the sensor array, and the movement of the downhole device is determined using the first location and the second location.

17. The method of claim 13, wherein the sensor array is a tactile sensor array and driving the sensor array towards the wall of the borehole includes bringing the tactile sensor array in contact with the wall of the borehole.

18. The method of claim 13, wherein driving the sensor array towards the borehole wall includes activating an electromagnet.

19. A downhole system for use in a borehole, the downhole system comprising:a downhole device in the borehole;an electromagnet;a control unit configured to activate the electromagnet;an interaction device configured to interact with a wall of the borehole;wherein the electromagnet moves the interaction device towards the borehole wall when actuated.

20. The downhole system of claim 19, wherein the interaction device is a sensor array.-23- IM-#10773085.1

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