GB2532967A

GB2532967A - Determining Drill String Activity

Info

Publication number: GB2532967A
Application number: GB1421468.8A
Authority: GB
Inventors: Flander Mattias; Du Castel Bertrand
Original assignee: Schlumberger Holdings Ltd
Current assignee: Schlumberger Holdings Ltd
Priority date: 2014-12-03
Filing date: 2014-12-03
Publication date: 2016-06-08
Also published as: GB201421468D0

Abstract

An apparatus 102 for detecting translational and/or rotational movement of a drill pipe 58, comprising: a sensor head 110, stationary with respect to the wellbore for measuring longitudinal or rotary movement of the drill pipe. The sensor head may be attached to a riser 81, and may have a biasing spring 115 to urge the sensor into contact with the drill pipe. The sensor may be a wheel, ball, or optical sensor 107, and may feature a protective housing. The apparatus may comprise a processor configured to output data to an automation system, to identify when the drill string is in slips. Also included is a method of using the apparatus with a drilling automation system.

Description

DETERMINING DRILL STRING ACTIVITY

BACKGROUND

Embodiments of the present disclosure relate to an apparatus for determining the translational and/or rotational movement of a drill pipe in place in a drilled wellbore and to a method of operating such an apparatus, particularly but not exclusively for the purpose of providing the data to an automated drilling operating system.

Drilling of wellbores into geotechnical stratum can be a difficult undertaking under certain conditions. As is well known, geotechnical stratum can range from clay stratum to rock formations and, as a result, a large amount of variability is present during drilling operations.

Increasingly, such drilling operations are becoming automated. Such automation relies on high quality measurements, in order to deal with the wide range of unpredictable variability that may be encountered. To understand measurements made by or of the performance of the drilling system, it is necessary to understand the activity of the drilling system when the measurements are made.

For example, a drilling activity such as when the drilling system is "in slips" or "out-of-slips" is very important in order to understand data from the drilling system/wellbore since when the drilling system is in-slips, the drilling system is not rotating, and moreover, the movement between in-slips and out of slips rhythms drilling activities.

The term "slips" refers to a device that is used to grip the drill string in a relatively non-damaging manner. This device can include three or more steel wedges that are hinged together forming a near circle around the drill pipe. On the drill pipe side (inside surface of the slips), the slips are fitted with replaceable hardened tool steel teeth that embed slightly into the side of the drill pipe when the slips are activated. The outsides of the slips are tapered to match the taper of the rotary table.

After the rig crew places the slips around the drill pipe and in the rotary table, the driller can slowly lower the drill string. As the teeth on the inside of the slips grip the pipe, the slips are pulled down. This downward force pulls the outer wedges down providing a compressive force inward on the drill pipe and effectively locking everything together.

Then, the rig crew can unscrew the upper portion of the drill string (above the slips) while the lower part is suspended due to the mechanical action of the slips.

After another component is screwed onto the drill string, the driller raises the drill string to unlock the gripping action of the slips and the rig crew removes the slips from the rotary.

Thus, the term "in slips" is reflective of a drill string that is being encompassed by a slips mechanism, as described above, and is not being rotated. The term "out-of-slips" reflects times when the drill string is not confined by a slips mechanism and is moving, rotating and/or translating axially, in the borehole.

For drilling automation, it is very important to know when the drilling system is in-slips, as this knowledge can, amongst other things, be used to analyse received data about the performance of the drilling system. Additionally, the rhythm of the drilling system can be analysed from the in-slips data. Previously, automation systems have attempted to determine when the drilling system in in-slips from wellbore data, see, e.g., U.S. Patent Publication no. 2013/0124096, International Patent Publication no. W02010/010455 and International Patent Publication no. W02010/010453 in which slip activity is determined from existing surface sensors common in the oilfield, such as pressure data and hookload data.

However, such methods rely on indirect interpretation of data intended for a purpose other than detecting whether a drillpipe is "in-slips" or not. Moreover, an understanding of the data may be lost without direct knowledge of whether the drilling system is in or out of slips.

SUMMARY

In a first aspect, embodiments of the present disclosure relate to an apparatus for determining the translational and/or rotational movement of a drillpipe in place in a drilled wellbore, the apparatus comprising a device configured to be substantially stationary in relation to the surrounding wellbore, which device comprises a sensor head, the sensor head being positionable proximate to the surface of the drill pipe to be measured, the sensor head being configured to measure translational and/or rotational motion of the drill pipe relative to the sensor head.

Thus, the invention provides a means of directly determining slip activity and pipe movement by means of a sensor dedicated specifically to that task. The sensor monitors any movement by direct interrogation of the surface of the drill pipe.

Thus, the direct measurement can be more reliable and does not require indirect interpretation.

The apparatus is able to determine if the drill pipe is rotating or translating axially (in which case it can be determined that the drill pipe is out-of-slip) or whether it is stationary (in which case it is in slips).

Such an apparatus is ideally removed from the existing equipment of the drilling rig. In particular the rotating kelly could cause destruction of any measuring apparatus, in view of its irregular periphery. Additionally, the kelly bushing is an inappropriate location due to its rotating manner in use, which could also destroy any measuring sensors nearby.

These difficulties have been overcome by locating the apparatus beneath the rig floor and rotating table. Typically, the apparatus is located above the blowout preventer (BOP) so that it is reasonably close to the surface to enable it to be fitted and maintained relatively easily. In a preferred embodiment, the apparatus is mounted onto a riser, into which the drill pipe can freely move. For example, it could be disposed where the drill pipe enters the riser, e.g. bolted onto the riser or BOP. Such locations allow the apparatus to be installed without any modification to existing drilling equipment and the apparatus is out of the way of normal drilling operations.

The sensor head may have a drill pipe contact region, to provide physical contact between the sensor head and drill pipe. In some embodiments, the sensor head is not contacted with the pipe, but includes and optical probe or the like to determine the motion of the drill pipe with respect to the sensor.

In a preferred embodiment, the sensor head is urged against the drill pipe by a biasing means, such as a spring.

The sensor head may comprise a means of measuring movement of the drill pipe. The movement of the drill pipe may comprise rotational movement of the drill pipe, translational movement of the drill pipe, or both. However, detection of any motion of the drill pipe may be used to determine whether or not the drill pipe is in slips or not since the drill pipe will be held stationary when the drill pipe is in-slips. In some embodiments, a movement threshold may be set for the in-slips determination to account for inaccuracy in sensing movement and/or vibrational movement or the like of the drill pipe..

In one embodiment the sensor head comprises an encoder ball, which is in physical contact with the drill pipe. Such an encoder device would then move in a 25 corresponding manner in response to any movement of the drill pipe due to the friction between the ball and drill pipe surface. The movement of the ball could then be measured in known manner, e.g. by monitoring movement of magnets within the encoder wheel or ball. Such a device would therefore be able to measure both rotational movement and translational movement of the drill pipe. 30 In another embodiment the sensor head comprises an encoder wheel, which is in physical contact with the drill pipe. Such a sensor would only be able to measure the rotational movement or the translational movement of the drill pipe however. Thus a further sensor would be required, which could be a second encoder wheel or some other device, e.g. use of a ball-bearing ring around the drill pipe to monitor for rotational movement.

In another embodiment the sensor head comprises an optical device for measuring the relative movement of the drill pipe. For example, this can comprise a light-emitting diode (LED) that bounces light off that drill pipe surface onto a complementary metal-oxide semiconductor (CMOS) sensor. The CMOS sensor sends each image to a digital signal processor for analysis, which can be installed on the apparatus itself or some nearby processing unit.

In this embodiment a shroud of the like may be used to block out ambient light. However, ambient light is not an issue when the optical sensor comprises an LED, laser diode and/or the like since a selective sensor may be used with such electromagnetic sources. Furthermore, in some embodiments, the ambient light itself may be used to provide for illuminating a surface of the drill pipe and providing for image correlation tracking to determine drill pipe motion.

The apparatus can be simply clamped in place or positioned as desired by use of permanent magnets.

In a second aspect, embodiments of the present disclosure relate to a method of measuring the translational and rotational movement of a drill pipe in a wellbore, the method comprising employing an apparatus as described herein, measuring the translational and rotational movement of the drill pipe, followed by outputting the measurement data to a data recording device.

In a preferred embodiment, if no movement is detected then a determination of "in slips" is provided to an automated drilling operating system. Similarly, if motion is detected. a determination of "out of slips" may be provided to an automated drilling operating system.

In embodiments of the present disclosure, a guard or shroud may contact the drill pipe and prevent materials from contaminating the sensor head. For example, the guard may comprise a compliant material that is urged into contact with the drill pipe and provides a barrier around the sensor head.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is described in conjunction with the appended figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

Figure 1 is a schematic representation of a drilling rig.

Figure 2 is a schematic representation of a region below the rig floor of the drilling rig, showing the placement location of an apparatus according to the

present disclosure.

Figure 3 is a close-up view of the apparatus shown in figure 2.

Figure 4 is a schematic representation of a region below the rig floor of the drilling rig, showing the placement location of another apparatus according to the present disclosure.

Figure 5 is a close-up view of the apparatus shown in figure 4.

In the appended figures, similar components and/or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a dash and a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label.

DETAILED DESCRIPTION

The ensuing description provides preferred exemplary embodiment(s) only, and is not intended to limit the scope, applicability or configuration of the invention. Rather, the ensuing description of the preferred exemplary embodiment(s) will provide those skilled in the art with an enabling description for implementing a preferred exemplary embodiment of the invention. It being understood that various changes may be made in the function and arrangement of elements without departing from the scope of the invention as set forth in the appended claims.

Specific details are given in the following description to provide a thorough understanding of the embodiments. However, it will be understood by one of ordinary skill in the art that the embodiments maybe practiced without these specific details. For example, circuits may be shown in block diagrams in order not to obscure the embodiments in unnecessary detail. In other instances, well-known circuits, processes, algorithms, structures, and techniques may be shown without unnecessary detail in order to avoid obscuring the embodiments.

Also, it is noted that the embodiments may be described as a process which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations can be performed in parallel or concurrently. In addition, the order of the operations may be re-arranged. A process is terminated when its operations are completed, but could have additional steps not included in the figure. A process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination corresponds to a return of the function to the calling function or the main function.

Moreover, as disclosed herein, the term "storage medium" may represent one or more devices for storing data, including read only memory (ROM), random 30 access memory (RAM), magnetic RAM, core memory, magnetic disk storage mediums, optical storage mediums, flash memory devices and/or other machine readable mediums for storing information. The term "computer-readable medium" includes, but is not limited to portable or fixed storage devices, optical storage devices, wireless channels and various other mediums capable of storing, containing or carrying instruction(s) and/or data Furthermore, embodiments may be implemented by hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof. When implemented in software, firmware, middleware or microcode, the program code or code segments to perform the necessary tasks may be stored in a machine readable medium such as storage medium. A processor(s) may perform the necessary tasks. A code segment may represent a procedure, a function, a subprogram, a program, a routine, a subroutine, a module, a software package, a class, or any combination of instructions, data structures, or program statements. A code segment may be coupled to another code segment or a hardware circuit by passing and/or receiving information, data, arguments, parameters, or memory contents. Information, arguments, parameters, data, etc. may be passed, forwarded, or transmitted via any suitable means including memory sharing, message passing, token passing, network transmission, etc. It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

Turning to the figures, figure 1 shows a drilling system 10 using automatic rig state detection, according to one embodiment of the present invention. Drill string 58 is shown within borehole 46. Borehole 46 is located in the earth 40 having a surface 42. Borehole 46 is being cut by the action of drill bit 54. Drill bit 54 is disposed at the far end of the bottomhole assembly 56 that is attached to and forms the lower portion of drill string 58. Bottomhole assembly 56 contains a number of devices including various subassemblies.

Measurement-while-drilling (MWD) subassemblies are included in subassemblies 62. Examples of typical MWD measurements include direction, inclination, survey data, downhole pressure (inside the drill pipe, and outside or annular pressure), resistivity, density, and porosity. Also included is a subassembly 62 for measuring torque and weight on bit. The signals from the subassemblies 62 are preferably processed in processor 66. After processing, the information from processor 66 is communicated to pulser assembly 64. Pulser assembly 64 converts the information from processor 66 into pressure pulses in the drilling fluid. The pressure pulses are generated in a particular pattern which represents the data from subassemblies 62. The pressure pulses travel upwards though the drilling fluid in the central opening in the drill string and towards the surface system. The subassemblies in the bottomhole assembly 56 can also include a turbine or motor for providing power for rotating and steering drill bit 54. In different embodiments, other telemetry systems, such as wired pipe, fiber optic systems, acoustic systems, wireless communication systems and/or the like may be used to transmit data to the surface system.

The drilling rig 12 includes a derrick 68 and hoisting system, a rotating system, and a mud circulation system. The hoisting system which suspends the drill string 58, includes draw works 70, fast line 71, crown block 75, drilling line 79, traveling block and hook 72, swivel 74, and deadline 77. The rotating system includes kelly 76, rotary table 88, and engines (not shown). The rotating system imparts a rotational force on the drill string 58 as is well known in the art. Although a system with a kelly and rotary table is shown in figure 1, those of skill in the art will recognize that the present invention is also applicable to top drive drilling arrangements. Although the drilling system is shown in figure 1 as being on land, those of skill in the art will recognize that the present invention is equally applicable to marine environments.

The mud circulation system pumps drilling fluid down the central opening in the drill string. The drilling fluid is often called mud, and it is typically a mixture of water or diesel fuel, special clays, and other chemicals. The drilling mud is stored in mud pit 78. The drilling mud is drawn in to mud pumps (not shown), which pump the mud though stand pipe 86 and into the kelly 76 through swivel 74 which contains a rotating seal The mud passes through drill string 58 and through drill bit 54. As the teeth of the drill bit grind and gouges the earth formation into cuttings the mud is ejected out of openings or nozzles in the bit with great speed and pressure. These jets of mud lift the cuttings off the bottom of the hole and away from the bit 54, and up towards the surface in the annular space between drill string 58 and the wall of borehole 46.

At the surface the mud and cuttings leave the well through a side outlet in blowout preventer 99 and through mud return line (not shown). Blowout preventer 99 comprises a pressure control device and a rotary seal. The mud return line feeds the mud into separator (not shown) which separates the mud from the cuttings. From the separator, the mud is returned to mud pit 78 for storage and re-use.

Various sensors are placed on the drilling rig 10 to take measurement from the drilling equipment. In particular hookload is measured by hookload sensor 94 mounted on deadline 77, block position and the related block velocity are measured by block sensor 95 which is part of the draw works 70. Surface torque is measured by a sensor on the rotary table 88. Standpipe pressure is measured by pressure sensor 92, located on standpipe 86. Additional sensors may be used to detect whether the drill bit 54 is on bottom. Signals from these measurements are communicated to a central surface processor 96.

In addition, mud pulses traveling up the drill string are detected by pressure sensor 92. Pressure sensor 92 comprises a transducer that converts the mud pressure into electronic signals. The pressure sensor 92 is connected to surface processor 96 that converts the signal from the pressure signal into digital form, stores and demodulates the digital signal into useable MWD data.

According to various embodiments described above, surface processor 96 is programmed to automatically detect the most likely rig state based on the various input channels described. Processor 96 is also programmed to carry out the automated event detection as described above. Processor 96 preferably transmits the rig state and/or event detection information to user interface system 97 which is designed to warn the drilling personnel of undesirable events and/or suggest activity to the drilling personnel to avoid undesirable events, as described above. In other embodiments, interface system 97 may output a status of drilling operations to a user, which may be a software application, a processor and/or the like, and the user may manage the drilling operations using the status.

Processor 96 may be further programmed, as described below, to interpret the data collected by the various sensors provided to provide an interpretation in terms of activities that may have occurred in producing the collected data. Such interpretation may be used to understand the activities of a driller, to automate particular tasks of a driller, and to provide training for drillers.

The kelly 76 can be or include any configuration having a set of polygonal connections or splines on the outer surface type that mate to a kelly bushing such that actuation of the rotary table can rotate the kelly.

An upper end of the drill string 58 can be connected to the kelly 76, such as by threadably reconnecting the drill string 58 to the kelly, and the rotary table 88 can rotate the kelly, thereby rotating the drill string 58 connected thereto.

Although not shown, the drill string 58 can include one or more stabilizing collars.

A stabilizing collar can be disposed within or connected to the drill string 58, in which the stabilizing collar can be used to engage and apply a force against the wall of the well 46. This can enable the stabilizing collar to prevent the drill pipe string 58 from deviating from the desired direction for the well 46. For example, during drilling, the drill string 58 can "wobble" within the well 46, thereby allowing the drill string 58 to deviate from the desired direction of the well 46. This wobble action can also be detrimental to the drill string 58, components disposed therein, and the drill bit 116 connected thereto. A stabilizing collar can be used to minimize, if not overcome altogether, the wobble action of the drill string 58, thereby possibly increasing the efficiency of the drilling performed at the well site and/or increasing the overall life of the components at the well site.

Figure 2 shows detail of the region below the rig floor shown in figure 1. It can be seen that the BOP 99 is connected to a riser 81, which terminates with a ball bearing head 98. Into this passes the drill pipe 58, which is in turn connected to Kelly 76.

As described, the rotating table 88 is connected to the kelly bushing 84, which in turn is connected to kelly 76. As the table 88 is urged to rotate, the bushing 84 rotates and so does the Kelly 76.

Also shown is the location of a wheel encoder 100, constituting an apparatus according to the present invention. The wheel encoder 100 is bolted onto the top of the riser 98 and so does not interfere with existing drilling equipment.

Figure 3 shows the detail of the encoder wheel 100. The encoder wheel comprises a pipe-contacting wheel 104, which is urged against the surface of the drill pipe 58 by the action of joint 105 and spring 106. Frictional contact between the wheel 104 and the pipe produces a motion of the wheel 104. By placing a pair of wheels in an orthogonal arrangement, motion in different directions may be determine by the encoder wheel 100. However, the wheel(s) 104 may be damaged by contact with the pipe. As such, in a preferred embodiment, the pipe contacting wheel 104 comprises a track ball or the like that is configured to move in response to a frictional interaction with the pipe.

In aspects of the present invention, the track ball sits tightly in an opening of a housing (not shown) containing the encoder wheel 100, preventing ingress of contaminants in to the encoder wheel 100. In such an arrangement, the joint 105 and spring 106 may be disposed within the housing.

Figure 4 shows detail of the region below the rig flood as shown in figure 1, in 15 other embodiments of the disclosure. It can be seen that the BOP 99 is connected to a riser 81, which terminates with a ball bearing head 98. Into this passes the drill pipe 58, which is in turn connected to Kelly 76.

Also shown is the location of an optic tracker 102, constituting an apparatus according to the present invention. The optic tracker 102 is bolted onto the top of the riser 98 and so does not interfere with existing drilling equipment.

Figure 5 shows the detail of the optic tracker 102. The optic tracker 102 comprises a sensor head 110 which comprises an LED and photoreceptor 107 and drill pipe contact points 108, which can be a simple plastic pad or the like.

In such an embodiment, digital image correlation may be used to determine the motion of the drill pipe. Image sensors in the sensor head 110 image the surface of the drill pipe 58. The surface of the drill pipe 58 is illuminated by a light emitting diode, to produce distinct shadows in the image captured by an image sensor, the photoreceptor 107. Images of the surface of the drill pipe 58 are captured in continuous succession and compared with each other to determine motion of the drill pipe 58.

In some embodiments, the drill pipe contact points 108 may comprise a guard that encircles the LED and photoreceptor 107. In this way, the LED and photoreceptor 107 may be protected from contaminants on the drill pipe 58. The guard may have a surface that minimizes frictional interaction between the drill pipe 58 and the guard. In other embodiments, the optic tracker 102 may be configured not to contact the drill pipe 58, and in fact because only the actual motion of the drill pipe 58 may be recorded by the optic tracker 102, rather than the actual amount of motion, the optic tracker 102 may be positioned a distance from the drill pipe 58, protecting the optic tracker 102 from interactions with the drill pipe 58. A drape or the like may be used to isolate the LED and photoreceptor 107 from external light. In some embodiments, the wavelength of the optical radiation may be selected to provide that the LED and photoreceptor 107 are operable even in the presence of external lighting/natural light. A laser or the like may be used to provide for increased intensity of the optical radiation.

A processor or the like (not shown) may be used to process motion of the drill pipe 58 and communicate whether or not the drilling system is in or out of slips to an automation system The sensor head 110 is urged against the surface of the drill pipe 58 by the action of joints 112,113 and spring 115. As people of skill in the art will appreciate, compliant materials, springs etc. may be arranged to urge the sensor head 110 into contact with the pipe.

In some embodiments, the tracker may comprise a tracker ball and an optic tracker and a process may cross-correlate the output from the two trackers to determine motion of the drill pipe 58. Similarly, a plurality of ball trackers may be used in the tracker to provide redundancy and/or to make sure at least one ball tracker is in proper contact with the drill pipe 58. Large tracker ball diameters, of the order of several centimetres or larger, may provide a rugged tracker that may be configured to be urged by a compliant means into direct contact with the drill pipe 58 The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R.

§1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

Claims 1. An apparatus for determining the translational and/or rotational movement of a drill pipe in place in a drilled wellbore, the apparatus comprising: a device configured to be substantially stationary in relation to the surrounding wellbore, wherein the device comprises: a sensor head, the sensor head being positionable proximate to the surface of the drill pipe to be measured, and wherein the sensor head is configured to measure translational and/or rotational motion of the drill pipe relative to the sensor head.
2. An apparatus according to claim 1, which is located beneath the rig floor and rotating table.
3. An apparatus according to claim 2, which is located above the blowout preventer (BOP).
4. An apparatus according to claim 3, which is mounted onto a riser, into which the drill pipe can freely move.
5. An apparatus according to claim 4, which is located right where the drill pipe enters the riser.
6. An apparatus according to claim 1, wherein the sensor head has a drill pipe contact region, to provide physical contact between the sensor head and drill pipe.
7. An apparatus according to claim 6, wherein the sensor head is urged against the drill pipe by a biasing means.
8. An apparatus according to claim 1, wherein the sensor head comprises an encoder ball, which is in physical contact with the drill pipe.
9. An apparatus according to claim 8, wherein the encoder ball and the sensor head are encased in a housing configured to prevent contamination of the sensor head.
10. An apparatus according to claim 9, wherein the housing comprises a complaint guard for contacting the drill pipe and guarding the encoder ball.
11. An apparatus according to claim 1, wherein the sensor head comprises an encoder wheel, which is in physical contact with the drill pipe.
12. An apparatus according to claim 1, wherein the sensor head comprises an optical device for measuring the relative movement of the drill pipe.
13. An apparatus according to claim 12, wherein the optical device comprises a red light-emitting diode (LED) that bounces light off that drill pipe surface onto a complementary metal-oxide semiconductor (CMOS) sensor.
14. An apparatus according to claim 12, wherein the optical device comprises one of an LED or a laser diode and an image sensor.
15. An apparatus according to claim 12, further comprising: a processor configured to correlate images produced by the image sensor to identify lateral and/or rotational motion of the drill pipe.
16. An apparatus according to claim 15, wherein the processor is configured to communicate to an automation system that the drill pipe is in slips when the drill pipe is motionless or motion of the drill pipe falls below a threshold value.
17. An apparatus according to claim 1, which is clamped in place or positioned as desired by use of permanent magnets.
18. A method of measuring the translational and rotational movement of a drill pipe in a wellbore, the method comprising employing an apparatus according to claim 1, measuring the translational and rotational movement of the drill pipe, followed by outputting the measurement data to a data recording device.
19. A method according to claim 14, wherein if no movement is detected then a determination of in slip" is provided to an automated drilling operating system.
20. A method for determining whether a drill pipe of a drilling system extending into a wellbore being drilled by the drilling system is in slips. comprising: Illuminating a surface of the drill pipe; repeatedly capturing images of the illuminated surface of the drill pipe; and using a processor to compare the repeatedly captured images to determine whether the drill pipe is in lateral or rotational motion.
21. The method of claim 20, wherein at least one of an LED or a laser is used to illuminate the surface of the drill pipe.
22. The method of claim 20, further comprising: communicating the determination as to whether the drill pipe is in lateral or rotational motion to an automation system controlling operation of the drilling system.
23. The method of claim 20, wherein the illuminated surface of the drill pipe is disposed below a rig floor of the drilling system.