AN APPARATUS AND METHOD FOR INSPECTING COILED TUBING

Embodiments of the present disclosure relate to a coiled-tubing system, a coiled tubing inspection tool and methods for using same. The system comprises coiled tubing that is wound about a coiled tubing reel and a coiled tubing injector head that is connected to an oil-and-gas well above a pressurized zone. The coiled-tubing system also includes the inspection tool that is connected to the well within the pressurized zone. The inspection tool is configured to generate a magnetic field and to detect changes in the magnetic field as a section of coiled tubing approaches, moves through and moves away from the inspection tool. Detecting changes in the magnetic field may be indicative of a damaged section of the coiled tubing.

TECHNICAL FIELD

This disclosure generally relates to oil-and-gas operations. In particular, the disclosure relates to an apparatus and method for inspecting coiled tubing.

BACKGROUND

Coiled tubing is a continuous length of flexible, metal-walled tubing that can be used in various oil-and-gas operations. Coiled tubing can be stored and transported on a reel. During well interventions, the coiled tubing is inserted into an oil-and-gas well to perform any of fracking, milling, sand cleanouts or perforating. At least one benefit of coiled tubing over other known intervention methods, such as slick line and wire line, is that coiled tubing can be used to conduct pressurized fluids down into the well. Also, coiled tubing can be pushed downhole, which allows easier access to deviated or horizontal sections of a well that slick line and wire line cannot access easily.

Coiled tubing can also be used in drilling operations. At least one advantage of coiled tubing over other known drilling methods is that there are no connections to be made as there is with jointed tubing and, therefore, it is faster to move sections of the coiled tubing into or out from the well bore than jointed-tubing drill strings.

The integrity of coiled tubing can become compromised during normal use. For example, coiled tubing can become damaged during any of: being unwound from the reel, use during a well intervention or drilling operation downhole, being rewound onto the reel, during transport or any combinations thereof. Coiled tubing may also be damaged while it is exposed to the harsh down-hole environment of an oil-and-gas well. Regardless of the cause, the damage may be embodied by perforations, dents or otherwise weakened areas in the coiled tubing's metal wall. This damage can result in leaks, pressure loss, fluid loss and in some instances the coiled tubing may break. If the coiled tubing breaks while downhole, equipment that is connected to the coiled tubing can be lost as can any fluids that are being conducted through the coiled tubing. Broken coiled-tubing and lost equipment causes downtime at the well and often requires recovery operations, both of which are costly.

SUMMARY

Some embodiments of the present disclosure relate to a coiled-tubing system for inserting and withdrawing coiled tubing into a well that has a pressure-containment section. The system comprises coiled tubing that is windable about a coiled tubing reel. The system also comprises a coiled tubing injector head that is connected to the well above the pressure-containment section. The system also comprises an inspection tool that is connected to the well within the pressure-containment section. The inspection tool is configured to generate a magnetic field and to detect one or more changes in the magnetic field as a section of coiled tubing approaches, passes through and moves away from the inspection tool.

Some embodiments of the present disclosure relate to a coiled-tubing inspection tool that comprises a body, one or more magnets and one or more sensors. The body defines a central passageway that is configured to receive coiled tubing therethrough. The one or more magnets that are configured to generate a magnetic field that extends at least partially across the central passageway. The one or more sensors are configured to detect one or more properties of the magnetic field and to detect one or more changes in the properties of the magnetic field as the coiled tubing approaches, moves through and moves away from the central passageway.

Some embodiments of the present disclosure relate to a method for detecting a damaged section of coiled tubing within a pressurized section of a well. The method comprises the steps of: generating a magnetic field within the pressurized section of the well; exposing the coiled tubing to the magnetic field while moving the coiled tubing through the pressurized section of the well; and detecting any changes in the magnetic field as the coiled tubing approaches, moves through and moves away from the magnetic field. In some embodiments of the present disclosure, the changes in the magnetic field are substantially caused by the damaged section of the coiled tubing.

Some embodiments of the present disclosure relate to positioning the inspection device within the pressurized section of the well. This positioning may avoid catastrophic events because a damaged section of the coiled tubing can be detected by the inspection device at a location, within the pressurized section of the well, where there is a substantially small or no pressure differential and/or less of a bending force acting upon the damaged section. If a damaged section of the coiled tubing is detected within the pressurized section, then the fluid pressure inside of the coiled tubing can be relieved, for example by bleeding-off fluids and relieving the pressure, so that when the damaged section is removed from the pressurized section the damaged section will not be subjected to a pressure differential. Subjecting the damaged section to a pressure differential outside of the pressurized zone of the well may result in the coiled tubing rupturing outside of any pressure containment mechanisms of the well, which is a serious safety concern. Also, the coiled tubing can become further damaged and even break which may cause a portion of the coiled tubing, and any tools attached thereto, to fall down into the well.

DETAILED DESCRIPTION

As used herein, the term “about” refers to an approximately +/−10% variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.

FIG. 1shows a schematic of a coiled-tubing system10that is used in an oil and/or gas well100. The coiled-tubing system10comprises a coiled-tubing reel12that is controlled by equipment within a coiled-tubing control cab13. The coiled tubing14that is wound around the reel12can extend towards a guide arch16, which is also known as a gooseneck, and into a coiled-tubing injector head20. The coiled-tubing injector head20may guide the coiled tubing14as it is inserted into the well100and withdrawn from of the well100. The coiled tubing14can be used to introduce fluids into the well100and it may also be used to actuate one or more downhole tools. The coiled tubing14may have a substantially constant cross-sectional diameter.

FIG. 1shows an above-surface portion102of the well100that is above a surface101into which the well100extends. The portion of the well100that is below the surface101, and not specifically shown inFIG. 1, is referred to herein as a downhole portion105. The above-surface portion102of the well100comprises a coiled-tubing riser104. Generally, the riser104is in fluid communication with the downhole portion105of the well100via a central bore50of the well100(shown inFIG. 7). Accordingly, the fluid pressure within the riser104is generally similar to the downhole portion105. As such the components of the above-surface portion102that are exposed to generally similar fluid pressure as the downhole portion105may be housed within a pressure-containment section103. For clarity, when pressurized fluid is being conducted through the coiled tubing14the fluid pressure difference across the outer surface of the coiled tubing14within the pressure-containment section103may be smaller than when the coiled tubing14is outside of the pressure-containment section103.

In order to control the pressure within the pressure-containment section103there may be one or more pressure control mechanisms106, such as one or more preventers, blow out preventers (BOP), bleed lines, pack-offs or strippers.FIG. 1shows non-limiting examples of the pressure control mechanisms106as including a primary BOP, and a coiled-tubing pack-off stripper106C. The injector head20may be positioned above one or more pack-off strippers106C and106D. The injector head20is not within the pressure-containment section103.

Embodiments of the present disclosure include an inspection tool200that is positioned under the injector head20and a first pack off stripper106C and above a second pack-off stripper106C2This positioning of the inspection tool200places it within the pressure-containment section103. Without being bound by any particular theory, positioning the inspection tool200at any point within the pressure-containment section103may allow the inspection tool200to detect a damaged portion15of the coiled tubing14. Furthermore, because the inspection tool200is located within the pressure-containment section103, this can be at a location where the pressure differential between the inside and the outside of the coiled tubing200is substantially less than the pressure differential between the inside and the outside of the coiled tubing14when the coiled tubing14is outside of the pressure-containment section103. For example, when the coiled tubing14is outside of and above the pressure-containment section103, atmospheric pressure may be exerted on the outside of the coiled tubing14and atmospheric pressure may be lower than pressurized fluids within the coiled tubing14. Detecting a damaged portion15when it is positioned within the pressure-containment section103may allow an operator to safely bleed off the fluid within the coiled tubing14and to equalize the fluid pressure within the coiled tubing14with atmospheric pressure before the coiled tubing14exits the pressure-containment section103. This bleed-off may avoid exposing a damaged section15of the coiled tubing14to a pressure differential between the inside and the outside of the coiled tubing14that can cause a catastrophic rupture of the coiled tubing14at the above-surface portion102of the well100. The damaged section15is a portion of the coiled tubing14where the integrity of the metal wall is structurally compromised. The damaged section15may also be referred to herein as a defect.

The inspection tool200can generate a magnetic field that extends at least partially across a central passageway234, as described herein below. The magnetic field is influenced by the metal wall of the coiled tubing14as it approaches, moves through and moves away from the inspection tool200. As one skilled in the art will appreciate, the movement of the coiled tubing14through the inspection tool200can when the coiled tubing14is being inserted into the well100and when it is being removed from the well100. The inspection tool200can detect changes in the magnetic flux density and/or the strength of the generated magnetic field that are caused by the coiled tubing14influencing the properties of the magnetic field. These detected changes are used to determine the integrity of the metal wall of the coiled tubing14. The inspection tool200is electronically connectible to a processor unit202, which may also be referred to as a controller, by a data transfer and power cord204or wirelessly, which may also be referred to herein as a wire. The processor unit202may also be electronically connectible to a display206. Optionally, the display206is positionable within the control cab13so that an operator can see a visual output of the processor unit202.

FIG. 2shows one embodiment of the inspection tool200that includes a first sensor array201that includes one or more sensor units208and one or more magnets216. Some embodiments of the inspection tool200include multiple sensor arrays201. Within the first sensor-array201shown inFIG. 2the sensor units208and the magnets216are arranged in an alternating pattern, but this alternating pattern is not required. The sensors described in U.S. Pat. No. 9,097,813, the entire disclosure of which is incorporated herein by reference, may be suitable for use in some embodiments of the present disclosure as a first sensor array201.

For example,FIG. 2shows one embodiment of the first sensor-array201according to the present disclosure. The array201comprises a body222having a plurality of sensor bores240therein each adapted to receive an individual sensor unit208therein. The body222may be an annular or ring-shaped spool having inner surface224and an outer surface226that extend between a top surface228and a bottom surface230. The inner surface224defines a central passage234. The inner and outer surfaces224,226are substantially cylindrical about a central axis, shown as line X inFIG. 2. In some embodiments of the present disclosure, the sensor unit208comprises a sleeve250and a sensor270. In some embodiments of the present disclosure, the sensor unit208comprises the sleeve250, the sensor270and a further magnet260. While the further magnet260is shown inFIG. 3Aas being proximal the central passage234, the further magnet260may also be proximal to the sensor270and distal from the central passage234. When the inspection tool200is integrated into the well100, the central axis X is co-axial with a central axis of the other components of the above-surface portion102of the well100. The central passage234extending through the inspection tool200may be sized and shaped to receive the coiled tubing14, which can be of various dimensions and sizes. In some embodiments of the present disclosure, the top surface228and the bottom surface230may be substantially planar along a plane normal to the central axis X. Optionally either or both of the top surface228and the bottom surface230may include a seal groove235extending annularly therearound for receiving a seal, as are known in the art.

In some embodiments of the present disclosure, the body222includes a plurality of bolt holes236that extend through the top surface228and the bottom surface230along an axis that may be substantially parallel to the central axis X. The bolt holes236may receive fasteners (not shown), such as bolts therethrough to secure the body222inline and in fluid communication with the other components of the above-surface portion102of the well100, according to methods known to those skilled in the art.

The sensor bores240extend from the outer surface226towards the inner surface224. In some embodiments of the present disclosure, the sensor bores240are blind bores extending to a predetermined depth within the body222that is a distance less than the distance from the outer surface226to the inner surface224. In such a manner, the sensor bore240will maintain a barrier wall between the sensor bore240and the central passage234so as to maintain a fluid tight seal. The barrier wall may have a thickness selected to provide adequate burst strength of the sensor unit208. In other embodiments of the present disclosure, the sensor bore240extends completely through the body222to fluidly communicate between the inner surface224and the outer surface226. The sensor bores240may be arranged about the central passage234along a common plane normal to the axis X of the central passage234although it is appreciated by one skilled in the art that other orientations may be useful as well.

The body222may have any height between the top and bottom surfaces228and230as is necessary to accommodate the sensor bores240. In some embodiments of the present disclosure, the body222has a height between about 3.5 inches and about 24 inches (about 89 mm and about 610 mm). The body222may have an inner diameter (ID) of the inner surface24that allows the passage of the coiled tubing14and an outer surface226OD that provides a sufficient depth for the sensor bores240.

The body222may be formed of a non-magnetic material, such as, by way of non-limiting example a nickel-chromium alloy. One example of a non-magnetic material is INCONEL® (INCONEL is a registered trademark of Vale Canada Limited). It will also be appreciated by one skilled in the art that other non-magnetic materials may also be useful such as but not limited to duplex stainless steel, super duplex stainless steel provided these materials do not interfere with the sensor's270operation as described below.

The sensor bores240are each configured to receive the sleeve250. The sleeve250comprises a tubular member that extends between a first end252and a second end254and having an inner surface256and an outer surface258. As illustrated inFIG. 2, the outer surface258of the sleeve250may be selected to correspond closely to the dimensions of the sensor bores240in the body222. The sleeves250are formed of a substantially ferromagnetic material, such as steel so as to conduct or propagate the magnetic field towards a sensor270that can be associated with each sensor bore240. The sleeves250are selected to have a sufficient OD to be received within the sensor bores240and an inner surface diameter sufficient to accommodate the sensor270therein. The sleeve250may also have a length that is sufficient to receive the sensor270therein. The OD of the sleeve250may also optionally be selected to permit the sleeve250to be secured within one sensor bore240by an interference fit or with the use of adhesives, fasteners, plugs or the like.

The sleeves250may also each include one or more magnets216that are positionable at the first end52thereof. The magnets216are selected to generate strong magnetic fields. In some embodiments of the present disclosure, the magnets216are oriented with the same magnetic pole facing the center of the inspection tool200to create a magnetic field that corresponds to the common centrally facing magnetic pole of the magnets216. The magnetic field may be strongest on or near the internal wall224of the inspection tool200and the use of multiple magnets216may create a substantially homogeneous and evenly distributed magnetic field within or about the inspection tool200. In particular, it has been found that rare earth magnets, such as but not limited to: neodymium, samarium-cobalt are useful. Electromagnets are also useful. The magnets216may be nickel plated, or not. The magnets216are located at the first ends252of the sleeves250and they are retained in place by the magnetic strength of the magnets216. Optionally, the sleeve250may include an air gap (not shown) between the magnet216and the barrier wall242of up to about 0.5 of an inch (about 13 mm) although other distances may be useful as well.

An individual sensor270is insertable into the open second end254of each sleeve250and is retained within the sleeves250by any suitable means, such as but not limited to: an adhesive, threading, a fastener or the like. In some embodiments of the present disclosure the sleeve250can be a solid article with an individual sensor270attached at one end thereof. The sensors270are selected to provide an output signal in response to the magnetic field in their proximity. For example, the sensors270may comprise magnetic sensors, such as a Hall Effect sensor although it will be appreciated that other sensor types may be utilized as well. In some embodiments of the present disclosure a Hall Effect sensor, such as a model SS496A1 sensor manufactured by Honeywell is useful. It will be appreciated that other sensors are also suitable. The sensor270may be located substantially at a midpoint within each sleeve250although other locations within the sleeve250may be useful as well. The sensors270may be oriented to focus towards the center of the inspection tool200.

The sensor270is configured to provide an output signal to the processor unit202. The sensor70may be wired via cord204or the sensor270may be wirelessly or otherwise connected to the processor unit202. The sensor270is configured so that the output signal represents a change that is detected in the magnetic field that passes through the metal wall of the coiled tubing14passing through the inspection tool200.

The processor unit202may be any one of the commonly available personal computers or workstations having a processor, a microprocessor, a field programmable gate array, programmable logic controller or combinations thereof that include a volatile and non-volatile memory, and an interface circuit for interconnection to one or more peripheral devices for data input and output. In some embodiments of the present disclosure, the processor unit202may include processor-executable instructions, in the form of application software, may be loaded into the memory of the controller202that allow the processor unit202to adapt its processor to receive, store and query various input signals. In some embodiments of the present disclosure, the processor unit202can also send one or more instructions or commands to other components of the inspection tool200. For example, the processor unit202can send a display signal to a display206that visually displays the signal output by one or more sensor arrays201over time (for example seeFIG. 3B,FIG. 3D,FIG. 3F,FIG. 4B,FIG. 4D,FIG. 4FandFIG. 5). The signal output represents the detected parameters of the magnetic field and changes thereto.

When a ferromagnetic object, such as coiled tubing14, approaches, moves through or moves away from the inspection tool200, the ferromagnetic object draws at least a portion of the magnetic field on to or about its surface, which may change the distribution of the magnetic field within in the inspection tool200. This changed distribution will be reflected in changes in the measurements of the one or more properties of the magnetic field made by the sensors270. When the coiled tubing14is moving into or out of the well100, the coiled tubing14is substantially centralized, as described further herein below. Also, the cross-sectional diameter of the coiled tubing14is substantially constant and, therefore, the distance between the inner surface of the inspection tool200and each of the sensors270and the outer surface of the coiled tubing14is substantially equal. This means that the one or more properties of the magnetic field detected by the inspection tool200remains substantially constant as the coiled tubing14is moving through the well100until a damaged section15approaches, moves towards or moves away from the inspection tool200. The damaged section15will change how the magnetic field is distributed across that damaged portion of the coiled tubing14and this change will be different from the otherwise substantially constant measurements of the one or more properties detected by the sensors270when undamaged sections of the coiled tubing14are approaching, moving through or moving away from the inspection tool200. In other words, any detected changes in the measurements of the one or more properties of the magnetic field may indicate a perturbation in the magnetic field caused by the damaged section15.

In some embodiments of the present disclosure, the coiled tubing14may be substantially centralized and mechanically restrained from lateral movement within the pressure-containment section103and optionally between the one or more pack-off strippers106C and106D. In some embodiments this mechanical restraint may substantially centralize the coiled tubing14within the inspection tool200and/or the magnetic field. The mechanical restraint may also reduce or substantially prevent lateral movement of the coiled tubing14when the coiled tubing14is proximal to the inspection tool200, whether moving or not. The mechanical restraint of the coiled tubing14may arise by one or more of the one or more pack-off strippers106C,106D, the central passage234of the inspection tool200itself or some other type of wellhead centralizer member may be used. For example, the central passage234may be configured to substantially centralize the movement of the coiled tubing14proximal to the inspection tool200. Because the coiled tubing14is mechanically restrained and because it has a substantially constant diameter, the changes in the properties of the magnetic-field that are detected by the inspection tool200may indicate that a damaged section15is approaching, moving through or moving away from the inspection tool200. For example, when the processor unit202receives the output signal from the inspection tool200, and the output signal indicates that there is a change in a detected property of the magnetic field, the processor unit202will convert the output signal to generate a visual output signal that indicates a damaged section15is approaching, moving through or moving away to the inspection tool200. Because the inspection tool200is positioned within the pressure-containment section103, the movement of the coiled tubing14can be stopped, the pressurized fluids within the coiled tubing14can be bled off and the coiled tubing14can then be moved up and out of the injector head20for further inspection while substantially lowering the risk of a dangerous pressure-loss event at the well100.

The measurements of the one or more properties of the magnetic field captured by the sensors270depends on the strength or number of the magnets216positioned within the inspection tool200. However, changes in the magnetic-field strength within the inspection tool200can be due to a ferromagnetic object and the magnitude of those changes can depend on the dimensions and/or materials of the ferromagnetic object and/or the integrity of the ferromagnetic object (i.e. the presence or absence of any damaged sections in the metal wall of the coiled tubing).

FIG. 3Ashows a top plan view of the inspection tool200with the body222removed.FIG. 3Bshows a side elevation view of the inspection tool200with the first sensor array201arranged in substantially the same plane, which may also be referred to herein a lateral arrangement. In other embodiments of the present disclosure, the first sensor array201is arranged in a vertical arrangement where a magnet216is positioned above and another magnet216is positioned below the sensor unit208. In this vertical arrangement, the first sensor array201may comprise multiple groups of a sensor unit208vertically positioned between two magnets216that are positioned about the inner surface224of the inspection tool200. In other embodiments of the present disclosure, the inspection tool200may include multiple sensor arrays201with either or both of the lateral arrangement and the vertical arrangement or arrangements of sensor arrays201that are between the lateral and vertical arrangement. For example, the one or more sensor arrays201may be arranged at any degree between about 0 and about 90 degrees relative to vertical. In some embodiments of the present disclosure the one or more sensor arrays201may be arranged between about 30 and about 60 degrees relative to the vertical. In some embodiments of the present disclosure the one or more sensor arrays201may be arranged at about 45 degrees relative to the vertical.

Further to the lateral and vertical sensor arrays, additional sensor arrays may be positioned with an arrangement between lateral and vertical. For example, 45 degrees from vertical has proved advantageous.FIG. 4Ashows a section of coiled tubing14that is moving through the inspection tool200with the first sensor array201arranged in the lateral arrangement. For clarity, the inspection tool200is shown inFIGS. 4A, 4C and 4Ewith the same view as shown inFIG. 3Bso that the arrangement of the first sensor array201can be seen. As inFIG. 3B, the circular shapes depicted within the inspection tool200ofFIG. 4each represent one of the sensors208and the square shapes each represent one of the magnets216. InFIG. 4Athe section of coiled tubing14is moving downward into the well100. The coiled tubing14includes a damaged section15that is oriented generally co-axial with the coiled tubing14. The damaged section15is substantially perpendicular to the lateral arrangement of the first sensor array201and the damaged section15is substantially aligned to pass through a middle sensor208A of the inspection tool200.FIG. 4Bis a schematic diagram that shows a visual output that the processor unit202generates and communicates to the display206based upon changes in the magnetic field that are detected as the coiled tubing14and the damaged section15passes through the inspection tool200.

The visual output is at least partially based upon the orientation of the damaged section15relative to the magnetic field generated by the inspection unit200. The X axis of the visual display represents time and the Y axis represents the amplitude of the change in the magnetic field, for example changes in magnetic flux, as the damaged section15approaches, moves through and moves away from the inspection tool200. The visual outputs shown inFIG. 4andFIG. 5are based upon the coiled tubing14moving at substantially the same rate.

FIG. 4Cshows another section of coiled tubing14that is moving towards an inspection tool200with the first sensor array201arranged in the lateral arrangement. InFIG. 4Athis section of coiled tubing14is moving downward into the well100. The section of coiled tubing14includes a damaged section15A that is oriented generally perpendicular to the longitudinal axis of the coiled tubing14. The damaged section15A is substantially parallel to the lateral arrangement of the first sensor array201and the damaged section15is also aligned to pass through the middle sensor208of the inspection tool200. As shown inFIG. 4D, the amplitude of the change in the magnetic field signal is smaller than that shown inFIG. 4B. Without being bound by any particular theory, this result is due to the orientation and alignment of the damaged section15as compared to the damaged section15A and how much time these damaged sections15,15A are in proximity to the sensors208of the sensor array201.

In some embodiments of the present disclosure the inspection tool200may have two or more sensor arrays201. For example,FIG. 4Eshows an inspection tool200A with a first sensor array201A and a second sensor array201B. WhileFIG. 4Eshows the first sensory array201A as having a lateral arrangement and the second sensor array201B as having a vertical arrangement, the two sensor arrays201A,201B may have different arrangements, or not, and the first sensor array201A may have a vertical arrangement. The two sensor arrays201A,201B are spaced apart along the central axis of the inspection tool200so that the first array201A is positioned above the second array201B when the inspection tool200is positioned within the pressure-containment section103of the well100.FIG. 4Fshows the visual output that is generated when there are two sensor arrays201A,201B that have different arrangements. The amplitude of the visual out of the detected change in the magnetic field that is caused by the damaged section15is larger and more readily apparent inFIG. 4Fas compared toFIG. 4D

FIG. 5AandFIG. 5Cshow another section of the coiled tubing14with a damaged section15approaching the inspection tool200A. InFIG. 5Athe damaged section15is substantially aligned with the middle sensor208A of the first sensor array201A and inFIG. 5Cthe damaged section15is not substantially aligned with any sensor208of the first or second sensor arrays201A,201B.FIG. 5Dshows a smaller amplitude of the visual output of the detected change in the magnetic field that is caused by the damaged section15A as compared toFIG. 5B.

FIG. 5Eshows another section of the coiled tubing14with a damaged section15approaching an inspection tool200B that has three sensor arrays201C,201D and201E, respectively. The first sensor array201C and the third sensor array201E are shown as having a lateral arrangement and the second sensor array201D is shown as having a vertical arrangement. The three sensor arrays201A,201B and201C are spaced apart along the central axis of the inspection tool200so that the first array201A is positioned above the second array201B, which is positioned above the third array201C when the inspection tool200is positioned within the pressure-containment section103of the well100.FIG. 5Ealso shows that the middle sensor208A of the first sensor array201C is substantially aligned with a magnet216of the third sensor array201E. This relative alignment of the sensors208of one sensor array201as compared to the magnets216of another sensor array201may be referred to herein as being an offset arrangement. It will be appreciated by one of skill in the art that the arrangement and number of the sensor arrays201can be different among different embodiments of the present disclosure and the offset arrangement is not required.FIG. 5Fshows the amplitude of the visual output of the change in the magnetic field that is detected by the three sensor arrays201C,201D and201E as the damaged section15A approaches, passes through and moves away from the inspection tool200B. The amplitude of the visual output inFIG. 5Fis more readily detected than the visual output shown inFIG. 5D.

FIG. 6shows another embodiment of an inspection tool300A that can be used in the coiled-tubing system shown inFIG. 1. The inspection tool300A can be configured to receive the coiled tubing14therethrough. The inspection tool300A can move between a closed position (as shown inFIG. 6A), a partially-open position (as shown inFIG. 6B) and a fully-opened position (as shown inFIG. 6C).

In some embodiments of the present disclosure the inspection tool300A may comprise a body300and an optional second body306. The first body304comprises one or more magnetic field generators, such as the magnets216described above, and one or more magnetic sensors, such as the sensors270described above, that can be housed within bores (not shown) of the first body304. Each bore may be covered with a bore cap308. The bore caps308can ensure that the magnetic field generators and the magnetic sensors are retained within their respective bores. The magnetic field generators can be magnets216that create a magnetic field proximal the first body304. The sensors270can detect changes in the magnetic field and/or the magnetic flux proximal the first body300. As described above, the sensors270are configured to provide an output signal to the processor unit202. The sensor270is configured so that the output signal represents a change that is detected in the magnetic field that is caused by the coiled tubing14and any damaged sections15,15A passing through the inspection tool300A.

The first body304can include an actuating member (not shown) that allows the first body304to move between a closed position (as shown inFIG. 6A) and an open position (as shown inFIG. 6BandFIG. 6C). For example, the actuating member may be a hinge and the body304may be a clam-shell type of arrangement. The first body304may also include one or more connectors310that can hold the first body304in the closed position. WhileFIG. 6Ashows the connector310as a pin and slot arrangement, other types of connectors310are contemplated.

The second body306may comprise an upper second body306A that is positioned above the first body304and a lower second body306B that is positioned below the first body304. The upper bodies306A,306B can also move between a closed position (as shown inFIG. 6AandFIG. 6B) and an open position (as shown inFIG. 6C). When the first body304and the second body306are both open, the body300is in the fully-opened position. The second bodies306A,306B may also include actuating members and connectors312that allow the second bodies306A,306B to move between the open and closed positions and to hold the second bodies306A,306B in the closed position, respectively.

In some embodiments of the present disclosure the magnetic field generators may be electromagnets and when the first body304of the body300is in the closed position, the magnetic field generators may be activated and the magnetic field is generated. When the first body304is in the open position the magnetic field generators may be off.

In some embodiments of the present disclosure, the body300may comprise one or more sections that can be connected together to form a complete body300that is held together by multiple connectors312. In these embodiments the body300does not include an actuating member.

In some embodiments of the present disclosure the inspection tool300A may include multiple magnets216and multiple sensors270that are arranged in one or more arrays201, as described herein above. There may be single or multiple vertical, lateral or sensor arrays201that are arranged at any angle relative to the vertical.

FIG. 7shows another example of an inspection tool400that has many of the same components as the inspection tool200,300A described herein above. Components that are the same between the different inspection devices200,300A,400are referred to inFIG. 7using the same reference numbers as used in the other figures herein. The inspection tool400shown inFIG. 7is similar to the apparatus described in the applicant's prior patent application WO 2017/205955 entitled APPARATUS AND METHOD FOR MEASURING A PIPE WITHIN AN OIL WELL STRUCTURE, the entire disclosure of which is incorporated herein by reference. Briefly, the inspection tool400comprises a tubular body402that defines a central passage between first and second ends. The tubular body402has at least an outer surface that is formed of a non-magnetic material. In some embodiments of the present disclosure, some or all of the tubular body402is formed of a non-magnetic material. Each of the first and second ends has a flange404that extends outwardly therefrom, substantially perpendicular to the central passage. The flanges are connectible with other components of the well100so that the central passage is substantially aligned with the central bore50of the well100. The inspection tool400may include multiple magnets216and multiple sensors270that are arranged in one or more arrays201, as described herein above. There may be single or multiple vertical arrays201, lateral arrays201or sensor arrays201that are arranged at any angle relative to the central passageway. The arrays201may be positionable around the tubular body402upon the outer surface. The arrays201may operate in the same manner as described herein above to detect as a damaged section15of coiled tubing approaches, moves through or moves away from the inspection tool400.

The present disclosure also relates to a method500of inspecting coiled tubing14as the coiled tubing is being run into or out of the well100(as shown inFIG. 8, with some optional steps shown in dashed-line boxes). This method comprises at least a step of running502coiled tubing14so that it is received through an inspection tool200,200A,200B or300A. Generating504a magnetic field with the inspection tool200,200A,200B or300A and exposing the magnetic field to the coiled tubing14so that the magnetic field is attracted towards and distributed across the ferromagnetic walls of the coiled tubing14. Detecting and/or measuring 506 one or more parameters of the magnetic field, using the inspection tool200,200A or200B, as the coiled tubing14. Identifying508that a damaged section15,15A is approaching, moving through or moving away from the magnetic field by detecting a change in one or more properties of the magnetic field. The method may include an optional step of positioning510the inspection tool200,200A,200B and300A within the pressure-containment section103of the well100. The method further includes a step of measuring the detected magnetic-field changes and assessing whether the coiled tubing14has a damaged section15,15A.

In some embodiments of the present disclosure, the method may further comprise an optional step of filtering512by comparing the measurements of the one or more properties of the magnetic field, and any changes thereto, to known magnetic measurement curves that were obtained under known conditions of temperature, known dimensions and materials of ferromagnetic objects. For example, the step of filtering512may assist in correcting for changes in temperature proximal the inspection tool200and for identifying magnetic anomalies in the coiled tubing14that may each create a false signal that a damaged section15is approaching, moving towards or moving away from the inspection tool200. Additionally, the method may include an optional step of measuring 514 one or more properties of the well100itself. The measured one or more properties of the well100are any properties that can influence a magnetic field and may include but are not limited to: the geometry and material properties of the well100and any influence of other equipment that is operating proximal to the well100. Then these measurements may be applied as a magnetic offset calculation within the conversion performed by the processor unit202to correct for differences (in geometry, materials and nearby equipment) between different wells100in which the inspection tool200,300A,400may be used.

If the assessing step indicates that there is a damaged section15,15A, then the fluid inside of the coiled tubing14can be bled off so that when the coiled tubing14moves out of the pressure-containment section103, there is a substantially equal pressure acting on the inside and the outside of the coiled tubing14. The damaged section15can then safely be removed from the pressure-containment section103for further inspection, maintenance or removal.

While the embodiments of the present disclosure are described in reference to inspecting coiled tubing14as it moves through a well100, it is understood by those skilled in the art that these embodiments may also be used to inspect coiled tubing14before or after it is inserted into a well100.