WO2014007790A1

WO2014007790A1 - Measurement and evaluation of tubing strings while lowering into a wellbore

Info

Publication number: WO2014007790A1
Application number: PCT/US2012/032005
Authority: WO
Inventors: Charles M. Williams; Patrick A. BURNS, Jr.; Kevin J. Smith
Original assignee: Accu-Tally, Llc
Priority date: 2012-04-03
Filing date: 2012-04-03
Publication date: 2014-01-09

Abstract

An apparatus (50), system, method, and software are taught for measuring and evaluating a tubular member (30), such as a tubing string, being positioned downhole. One embodiment includes a spool (52) having a through bore (55) and one or more connectors for removably coupling the spool to a blowout preventer assembly (40). A displacement sensor (60, 160) and a tubing feature sensor (80) are both mounted to the spool in proximity to the through bore. The displacement sensor is responsive to an axial displacement of the tubular member within the through bore of the spool. The tubing feature sensor is responsive to a cross-sectional parameter of the received tubular member in proximity to the tubing feature sensor. The displacement sensor and tubing sensor may be used separately or in combination, such as to identify and locate features of a tubing string and to ascertain the depth of a well.

Description

MEASUREMENT AND EVALUATION OF TUBING STRINGS WHILE

LOWERING INTO A WELLBORE

BACKGROUND

Field of the Invention

[0001] The present invention relates to measuring and evaluating components of a tubing string as they are lowered into a wellbore.

Background of the Related Art

[0002] A hydrocarbon recovery well is a man-made hole in the earth's surface used to recover petroleum hydrocarbons, such as oil and gas, from an underground formation. The well site may be located anywhere along the earth's surface that a hydrocarbon formation is known or suspected, which may be on dry land or beneath a body of water. On land, the well is drilled by a crew operating a drilling rig. At a relatively shallow water site, the well may be drilled from a bottom-founded facility like a jack-up drilling rig or fixed offshore structure. In deepwater, the well may be drilled from a floating drilling vessel. In all cases, the creation and subsequent operation of an oil well involves a large expenditure in capital and human labor over the course of multiple phases, from drilling the well, to completing the well, and finally to operating the oil well to recover hydrocarbons. Safety is paramount at every phase of drilling and production, since the many people involved work with heavy machinery and with potential exposure to powerful natural phenomena, such as high subterranean pressures.

[0003] Various kinds of tubing are instrumental in constructing and operating a hydrocarbon recovery well. A tubing string is often formed by joining tubing segments of a particular type end to end. For example, a wellbore is initially formed using a drill string comprising tubular drill pipe segments. A bottom hole assembly (BHA) having a drill bit is provided at the lower end of the drill string, and the wellbore is formed by rotating the drill bit to liberate earthen materials, either by rotating the entire drill string from the surface or by rotating the bit relative to the drill string using a downhole motor. The hollow drill string allows drilling fluid ("mud") to be pumped downhole through the tubular drill string to help remove the liberated earthen materials from the wellbore. As the wellbore is drilled and the drill string advances downhole, additional segments of drilling pipe are assembled from above until the desired depth is reached. In preparing a cased-hole completion, the borehole is lined with a casing string that provides structural integrity to the drilled wellbore and isolates high pressure zones. A production tubing string may then be installed downhole, which serves as a conduit for retrieving the oil and gas. Like drill strings, casing strings and production tubing strings are also formed from segments joined end to end. Another type of tubing used in the oil and gas industry is coiled tubing, which is provided on a reel in a long, continuous supply, rather than as separate segments. Coiled tubing is often used in completion and production operations.

[0004] The depth of a well and the depth of various tubular components positioned downhole are very relevant to completing and operating a well. Some conventional depth measurements are a "driller's depth" and a "logger's depth." Driller's depth is associated with drilling operations and related activities, such as logging while drilling, measurement while drilling, and coring. Driller's depth is typically determined by individually measuring the separate drill string components above ground, before they are connected to the drill string. The individual lengths of components, such as drill pipe segments, drill pipe connectors, and components of the bottom hole assembly are manually measured and recorded, such as using a measuring tape or laser tool. This manual process is exposed to many opportunities for human error. A logger's depth may be obtained by tripping wireline equipment downhole, and is generally regarded as a more accurate measurement.

BRIEF SUMMARY

[0005] A first embodiment is an apparatus that comprises a spool having a through bore and one or more connectors for removably coupling the spool to a blowout preventer assembly. A displacement sensor and a tubing feature sensor are both mounted to the spool in proximity to the through bore. The displacement sensor is configured to sense an axial displacement of a tubular member within the through bore of the spool and to generate a signal in response to the axial displacement. The tubing feature sensor is configured to sense a cross-sectional parameter of the received tubular member in proximity to the tubing feature sensor and to generate a signal in relation to the cross- sectional parameter of the received tubular member.

[0006] A second embodiment is a system that comprises a blowout preventer assembly in sealed fluid communication with a wellhead. A spool coupled to the BOP assembly includes a through bore in fluid communication with respective through bores of the BOP assembly and the wellhead such that a tubular member lowered into the wellhead through the BOP assembly passes through the spool. A displacement sensor mounted to the spool in proximity to the through bore of the spool is configured for sensing an axial displacement of the tubular member within the through bore of the spool and generating a signal in relation to the sensed axial displacement. A tubing feature sensor mounted to the spool in proximity to the through bore is responsive to a cross- sectional parameter of the received tubular member in proximity to the tubing feature sensor and is configured for generating a signal in relation to the cross-sectional parameter of the received tubular member. A computer in electronic communication with the displacement sensor and the tubing feature sensor includes control logic for identifying and locating variations in the cross-sectional property of the tubular member with the sensed linear displacement of the tubular member.

[0007] A third embodiment is a method. A linear displacement of a tubing string is sensed, relative to a fixed location of a wellhead apparatus. A signal is generated in response to the linear displacement. A change in a cross-sectional parameter of the tubing string is sensed in proximity to the fixed location, in response to which another signal is generated. Variations in the cross-sectional property of the tubular member with the sensed linear displacement of the tubular member are identified and located.

[0008] A related embodiment comprises software for performing the method. The software may comprise computer usable program code embodied on a computer usable storage medium. The software may reside on a portable field computer, such as a tablet or laptop computer. BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

[0009] FIG. 1 is a generalized diagram of a well service rig installing a tubing string downhole in a well.

[0010] FIG. 2 is a side view of a specific example embodiment of the tubing measurement and evaluation system that includes a pair of opposing, roller-based displacement sensors and one tubing feature sensor.

[0011] FIG. 3 is a partially cut-away side view further detailing one embodiment of a roller type displacement sensor.

[0012] FIG. 4 is a side view of another example embodiment of the tubing measurement and evaluation system having an optical displacement sensor in lieu of a roller-type sensor.

[0013] FIG. 5 is a schematic diagram of a field computer for receiving and interpreting the signals generated by the tubing measurement and evaluation systems of FIGS. 2 and 4.

[0014] FIG. 6 is an elevation view of the tubing measurement and evaluation system of FIG. 2 along with a selected portion of a tubing log corresponding to a portion of the tubing string currently under evaluation.

[0015] FIG. 7 is an elevation view of the tubing measurement and evaluation system, with the tubing string having been lowered to where a packer is positioned within the spool.

[0016] FIG. 8 is a flowchart generally outlining one example embodiment of a method for measuring and evaluating a tubing string.

DETAILED DESCRIPTION

[0017] A system, apparatus, method, and software are disclosed for automatically measuring and evaluating a tubing string as the tubing string is gradually lowered into a wellbore. One embodiment provides a special spool having integrated sensors for obtaining both the displacement of the tubing string and a varying local cross-sectional parameter of the tubing string as it passes by the sensors. The displacement and cross- sectional parameter may be used to obtain various information about the tubing string, such as the length of the tubing string, the number of segments of the tubing string, and to identify and locate various features of the tubing string. The spool may be referred to as a tubing feature locator (TFL) spool. The TFL spool may be coupled within a blowout preventer (BOP) assembly, such as above some BOP rams and below a stripper/rubber assembly. In use, the TFL spool is therefore at a fixed position relative to the floor of the well service rig. As a tubing string passes through the BOP assembly and wellhead while being lowered into the wellbore, the tubing string passes through the TFL spool.

[0018] A displacement sensor provided in the TFL spool senses an axial displacement of the tubular member within the TFL spool. The displacement sensor may include, for example, a spring-loaded roller biased into frictional engagement with the tubing string. A second type of sensor provided in the TFL spool is referred to as a tubing feature sensor. The tubing feature sensor is responsive to a local cross-sectional parameter of the tubular member, such as a density, thickness, and/or local volume of the tubular member. As the tubing string moves within the TFL spool, the TFL spool thereby provides both a positional signal responsive to an axial displacement of the tubular member and another signal responsive to a changing local parameter of the tubular member. These signals may be transmitted to a computer operating special- purpose software for evaluating the signals to obtain information, such as to determine the depth of the well and the length of the tubing string, to identify and distinguish different features of the tubing string, and to ascertain the positions of the identified features relative to the tubing string or to the well.

[0019] In one embodiment, the signals are communicated to a field computer system, which may incorporate a portable computer such as a laptop or tablet computer. The portable computer may connected to a computer dock powered by a rechargeable battery and/or a photovoltaic cell. Specialized software provided on the computer analyzes how the sensed cross-sectional parameter varies over the length of the tubing string, to distinguish different features of the tubing string. The features that may be sensed and identified include features of the tubing segments, such as upset portions and collars used to join consecutive tubing segments, and tubular components such as packers secured to an OD of the tubing string. Other features that may be sensed and identified include components of the bottom hole assembly (BHA) which are coupled to a lower end of the tubing string. The computer may further correlate the length and cross-sectional parameter to ascertain the positions of the sensed features either respect to the tubing string or a fixed datum like the rig floor. By sensing the collars or upset portions at the ends of the tubing segments, the computer may also automatically count (i.e. tally) the individual tubing segments. This enables automated, accurate, and detailed cataloging of the tubing string components and their relative positions.

[0020] The automated aspect of such a system, apparatus, method, and software may eliminate the costly and time-consuming step of having human operators individually measure each tubing string component separately before assembling the components within the tubing string. The measurements obtained are also more accurate, since high- precision displacement and tubing feature sensors may be incorporated within the TFL spool, and because these sensors respond automatically to movement of the tubing string relative to the TFL spool. Accuracy is further enhanced because the measurements obtained account for the cumulative weight and associated elongation of the tubing string suspended within the wellbore.

[0021] FIG. 1 is a generalized diagram of a well service rig 10 used for installing and/or retrieving a tubing string 30 downhole in a well 12. A tubing measurement and evaluation system 50 according to an embodiment of the invention is coupled within the BOP assembly 40 over the well 12. The tubing measurement and evaluation system 50 is used to automatically measure and evaluate the tubing string 30, such as to obtain an insertion length of the tubing string 30 and to locate and identify different components of the tubing string 30 as the tubing string 30 is lowered. In this example, the tubing string 30 is a production tubing string, which may be installed in a casing-lined wellbore. However, one of ordinary skill in the art will recognize that the principles by which the system 50 measures and evaluates the production tubing string 30 in this example may be extended to measuring and evaluating other types of tubing strings, including casing strings, drill strings, and even coiled tubing. The term "tubular member" as used herein encompasses, but is not limited to, individual tubing segments, tubing strings, tubular components mounted on a tubing string, coiled tubing, and combinations thereof. Some description and details follow regarding how the service rig 10 is used to install the production tubing string 30, as context for the subsequent discussion of the system 50 being used to measure and evaluate the tubing string 30 as it is positioned downhole.

[0022] A drilling rig (not shown) was initially provided at the well site to drill the well 12 in the ground 11. After the wellbore was drilled, the drilling rig was moved off of the well 12 and the service rig 10 was moved into place for completing the well 12 and to commence production. The service rig 10 may also be used for subsequent workover operations of the completed well 12. The well service rig 10 may be a mobile service rig (i.e. having wheels) for being driven to the site, or may be built on-site over the well 12. The well service rig 10 includes a rig platform 15 supported above ground 11. A towering structure supported on or near the rig platform 15 is referred to herein as a "mast" 14, which may be provided with a mobile service rig. The towering structure may alternatively be referred to as a "derrick" in the context of a service rig built on-site. The mast 14 has a trussed construction suitable for supporting large, heavy equipment used in well completion and workover operations. As generally understood in the art, a draw works supported from the mast 14 includes a crown block (not shown) at an upper end of the mast 14 and a traveling block 16 suspended from the crown block on a large diameter wire rope 18. A system of sheaves or pulleys provide a mechanical advantage for raising and lowering the traveling block 16 along with anything suspended from the traveling block 16. The traveling block 16 may be used to raise and lower various types of tubing and equipment used in completion and production.

[0023] An elevator 20 currently coupled to the traveling block 16 is specially adapted for use with production tubing. Production tubing tends to have a smaller diameter and less mass than a drill string used to drill the well or the casing used to line the well. Each tubing segment 31 has upset portions 32 at the ends where the diameter increases, at which the connection between tubing segments 31 is to be made. The upset portion 32 helps ensure that any failure of the tubing segment 31 occurs away from the upset portion 32. The elevator 20 has a hinge at one end and a latch at the other end, and is closed about the upset portion to grab it. In the closed position, the elevator arms are latched together to form a load-bearing ring around the component to be lifted, which in this case is the upset portion 32 of the tubing segment 31. The upset portion 32 on the tubing segment 31 is larger than the inside diameter of the closed elevator 20, so that the elevator 20 engages the shoulder or taper of the upset portion 32. The elevator 20 may be subsequently opened to release the tubing segment 31 or other component to be lifted, and may be swung away from the component. Note that on a drilling rig equipped with a top-drive, an elevator adapted for use with drill pipe can instead be secured to the top drive and used to raise and lower a drill string.

[0024] To add another tubing segment to the tubing string 30, the tubing string 30 may be temporarily suspended from slips 42, which are provided in the BOP assembly 40 in this example. As generally understood in the art, slips 42 include a set of dies having a tapered surface matching an internal taper of a bowl. A radially-inwardly facing surface of the dies include teeth for frictionally engaging an outer surface of the tubing to be suspended. The slips are said to be self-energizing, whereby the friction between the tubing and the slips allows the tubing to urge the slips downward and radially inward along the tapered surface of the bowl, into gripping engagement with the tubing. Commonly, as few as four sets of dies may be used in the slips 42. Larger diameter tubing may be supported by slips having a greater number of dies. An assembly commonly known as a "spider" has many sets of dies, such as twenty or more sets of dies, and operates according to the same basic principles as slips. The slips 42 temporarily suspend the tubing string 30 from a support location below an upper end 33 of the tubing string, leaving the upper end 33 accessible by the elevator 20 on the traveling block 16.

[0025] With the tubing string 30 temporarily suspended from the slips 42, the elevator 20 may be unlatched from the tubing string 30. A tubing segment, or a "stand" consisting of up to three tubing segments already connected end-to-end, may be added to the upper end 33 of the tubing string 30. The additional tubing segments or stands may be provided on the catwalk (not shown) of the services rig 10. In one scenario, a tubing segment or stand is pushed up a "V-door" comprising an opening in the derrick or mast at the rig floor 15. This brings one end of the segment or stand upward so that a crew member may latch the elevator 20 about the segment or stand. The traveling block 16 may then be controlled to position the retrieved segment or stand above the tubing string 30. The lower end of the suspended tubing segment or stand may be threadedly coupled to the upper end of the tubing string 30 using a connection tool 22. The connection tool 22 may be a power tong 22. In the present context of a well service rig, the power tong 22 is typically suspended by a cable 24 from the crown block. In the context of a drilling rig, a power tong may instead be supported on a rig floor. After connecting the stand or segment to the upper end of the tubing string 30, the slips 42 may be disengaged from the tubing string 30 so that the tubing string 30 may be further lowered into the well 12 by the traveling block 16. This process may be repeated for adding any number of tubing segments to the tubing string 30 until the desired depth is reached within the well 12.

[0026] When the desired length of the tubing string 30 and corresponding depth is reached, the tubing string 30 may be suspended indefinitely on a tubing hanger in the wellhead 48. The tubing hanger may be installed by a hanger running tool that lowers the hanger down the production bore of the wellhead 48 until it lands on a stop shoulder. The stop shoulder is formed by a decreased inner diameter portion defining a section of the production bore of the wellhead. The tubing string 30 may remain in place on the tubing hanger, suspended under its own weight, during production of hydrocarbons from the well 12.

[0027] To subsequently remove the tubing string 30 from the well 12, the process is essentially reversed. The elevator 20 is closed around an upper end of the tubing string 30 and the traveling block 16 is raised to lift the entire tubing string 30 until one or more tubing segments are exposed above the rig platform 15. Then the tubing string 30 is temporarily supported on the slips 42 while the one or more exposed tubing segments are disconnected from the tubing string 30 using the connection tool 22. The traveling block is then moved back down to grip the current uppermost tubing segment. The slips 42 are disengaged from the tubing string 30 and the tubing string is raised by the traveling block 16 to draw one or more additional tubing segments out of the well. The process of successively removing tubing segments and raising the tubing string 30 may be repeated until the entire tubing string 30 has been removed from the well 12 and disassembled.

[0028] The above description of lowering the tubing string into a well and alternately removing the tubing string from the well is just one example of how tubing may be lowered into a well and subsequently raised from a well. One of ordinary skill in the art will recognize that a myriad of different service rigs and rig equipment may be provided for assembling, lowering, raising, and disassembling different types of tubing, including tubing strings and coiled tubing. One of ordinary skill in the art will also appreciate that different equipment may be used for different types and sizes of tubing.

[0029] Referring still to FIG. 1, the BOP assembly 40 positioned over the wellhead 48 is used for controlling downhole pressures. The BOP assembly 40 comprises a plurality of components with concentric bores, such as the slips 42, a stripper 44, one or more BOPs 46, as well as the tubing measurement and evaluation system 50 that has been connected within the BOP assembly in this embodiment. Note that the bore of any component in the BOP assembly is not limited to being manufactured by the manufacturing step of a boring operation, and may instead be formed by other manufacturing steps such as molding. The concentric bores of these parts allow the tubing string 30 and tubular components supported on the tubing string 30 to be tripped down into the well 12 through the BOP assembly 40. Although the hydrocarbon fluids such as oil and gas are generally produced through the tubing string 30, the concentric bores of the BOP assembly 40, wellhead 48, and the well 12 provides a flow path for produced fluids in some circumstances that are beyond the scope of the present discussion. The one or more BOPs 46 may provide one or more sets of rams 47. For example, blind rams may be provided for selectively closing the annulus between the casing and the tubing string 30, and shear rams may be provided for shearing any tubing suspended in the well and completely shutting off flow in the event of an emergency. Standard BOP components such as rams are generally known in the art and do not require further discussion here.

[0030] The tubing measurement and evaluation system 50 includes a TFL spool 52 removably secured within the BOP assembly 40. Thus, the TFL spool 52 may be subsequently removed from the BOP assembly 40, such as for servicing the tubing measurement and evaluation system 50 or for subsequently using the tubing measurement and evaluation system 50 at another well site after the well 12 reaches the end of its useful service life. The upper and lower flanges 54, 56 may be used to secure the TFL spool 52 to corresponding flanges of other components in the BOP assembly 40. Corresponding flanges of components abutting the TFL spool 52 may be joined with the flanges 54, 56 using threaded fasteners. The TFL spool 52 is located above the BOP rams 47 but below the stripper 44, so that the stripper 44 may remove excess debris from the tubing string 30 prior to entering the TFL spool 52. The stripper 44 in this embodiment is unique to the particular service rig 10 and may be periodically discarded and replaced during well operations.

[0031] The TFL spool 52 includes at least one internally-mounted displacement sensor 60 and at least one tubing feature sensor 80 mounted within the TFL spool 52. The displacement sensor 60 is responsive to a linear, axial displacement of the tubing string 30 within the TFL spool 52. The tubing feature sensor 80 is responsive to a local cross-sectional parameter of the tubing string 30, such as a thickness or a density. It should be noted that, at its installed position within the BOP assembly 40, the TFL spool 52 is stationary while the tubing string 30 is moved relative to the stationary TFL spool 52. As the tubing string 30 is lowered or raised, the displacement sensor 60 generates a signal responsive to the linear, axial displacement of the tubing string, while the tubing feature sensor 80 simultaneously generates a signal responsive to the local thickness, density, volume, or other cross-sectional parameter of the tubing string 30.

[0032] FIG. 2 is a more detailed side view of a specific example embodiment of the tubing measurement and evaluation system 50 having a pair of opposing, roller-based displacement sensors 60A and 60B, and one tubing feature sensor 80. Each displacement sensors 60A, 60B includes an electrical connector 64, commonly referred to as an encoder, for connecting a signal wire or data cable external to the spool for carrying a signal representative of the sensed linear displacement of the tubing string. The TFL spool 52 includes a through bore 55 allowing the tubing string to pass through the TFL spool 52. The TFL spool 52 may be provided in different sizes, each accommodating a different tubing diameter or range of tubing diameters. In one example, the TFL spool 52 may have a nominal internal diameter (ID) of 7-1/16 inches and may be rated for a nominal maximum of 5,000 pounds per square inch (psi) of fluid pressure. A 7-1/16 spool ID is suitable for use with production tubing of a nominal 2-3/8 inch or 2-7/8 inch nominal tubing OD commonly used in the field. A TFL spool with a particular size and pressure rating may accommodate a range of different sizes and/or types of tubing strings. To accommodate an even greater range of size and type of tubing, the TFL spool may also be offered in a variety of different sizes and configurations.

[0033] The displacement sensors 60A, 60B in this example embodiment comprise spring-loaded rollers 62 that physically contact the tubing string as it moves within the through bore 55. The two displacement sensors 60A, 60B in this embodiment may be essentially identical, including respective spring-loaded rollers 62A, 62B of the same size. An additional spring-loaded roller 62C (without any electronic sensor elements) is also optionally mounted within the spool 52 to provide additional stabilization and centering to the tubing string. In the present example of a 7-1/16" TFL spool rated for 5,000 psi, each roller 62A-C may have a roller diameter of approximately 15 inches. The displacement sensors 60A, 60B and the additional, non-sensor, spring-loaded roller 62C are secured to the TFL spool 52 to internally position the rollers 62 within the through bore 55, so that the rollers 62 are in constant contact with a tubing string component positioned within the TFL spool 52. The rollers 62, as further detailed in FIG. 3, are free to travel radially to accommodate a changing OD of the tubing string as it is moved within the TFL spool 52. The rollers 62 may have an increased-friction surface, such as rubber-coated- steel rollers, to provide reliable frictional engagement with the tubing string.

[0034] In embodiments such as FIG. 2 having a plurality of roller-based displacement sensors, the rollers are circumferentially spaced around an axis of the spool 52. By way of example, the embodiment of FIG. 2 includes the two roller-based displacement sensors 60A, 60B mounted within the TFL spool 52 that are evenly spaced circumferentially, i.e., at approximately 180 degrees apart with respect to a central axis of the through bore 55. The additional, non-sensor, spring-loaded roller 62C is mounted within the spool 52 at about 90 degrees to the spring-loaded rollers 62A, 62B so the tubing string is simultaneously contacted at three different locations by the two sensor-containing rollers 62A, 62B and the non- sensor roller 62C. The use of the two (or more) displacement sensors 60A, 60B provides a redundant linear displacement measurement for improved reliability. The use of a plurality of circumferentially- spaced, spring-loaded rollers provides an additional centralizing feature, whereby the rollers 62 help to maintain a tubing string component centered within the through bore 55 of the TFL spool 52. Centering the tubing string within the TFL spool 52 helps minimize friction between the tubing string and the TFL spool 52 and other concentric bores of the BOP assembly in which the TFL spool 52 may be installed.

[0035] The displacement sensors 60A, 60B may be removably mounted to the TFL spool 52, so that the displacement sensors 60A, 60B may be serviced or replaced if necessary. Optional displacement sensor ports 58 are defined by the TFL spool 52, which extend from an outer surface 59 of the TFL spool 52 to the through bore 55. The displacement sensor ports 58 allow the respective displacement sensors 60A, 60B to be secured on the TFL spool 52 from the outside of the spool 52. Once inserted, the displacement sensors 60A, 60B are then mechanically secured to the TFL spool 52 at a mounting plate 66, such as using threaded connections 57. For example, threaded holes may partially extend through the wall of the TFL spool 52 without extending all the way to the through bore. Corresponding through holes on the mounting plate may align with the threaded holes on the TFL spool 52 for receiving a threaded fastener that mate with the threaded holes on the TFL spool 52. A sealing member such as an elastomeric O-ring may be provided to seal between the TFL spool 52 and the mounting plate 66. The displacement sensors 60A, 60B, the displacement sensor ports 58, and the mounting plate 66 are sized and located in consideration of the particular spool dimensions and intended tubing type to provide the desired positioning of the rollers 62A, 62B within the TFL spool 52. The non-sensor, spring-loaded roller 62C may be similarly mounted.

[0036] While the displacement sensors 60A, 60B are responsive to the linear displacement of the tubing string, the tubing feature sensor 80 provided in the TFL spool 52 is simultaneously responsive to a local cross-sectional parameter of the tubing string 30 in proximity to the tubing feature sensor 80. The tubing feature sensor 80 may be directly or indirectly responsive to a local thickness, effective density, or volume, which changes along the length of the tubing string 30. For example, the thickness, volume, and/or effective density of a tubing segment is increased at locations of the upset ends of abutting tubing segments. The thickness, volume, and/or effective density will also increase at locations where a tubular component, such as a packer, is secured to the tubing string. The tubing feature sensor 80 generates a signal responsive to such changes in the cross-sectional parameter of the tubing string. [0037] In one embodiment, the tubing feature sensor 80 comprises spaced-apart magnets 82, 84 and a coil 86 mounted between the magnets 82, 84. As the tubing string is moved axially within the TFL spool it moves relative to the tubing feature sensor 80. The tubing feature sensor 80 is responsive to a change in metal thickness or volume, whereby lines of magnetic flux between the two opposing magnets 82, 84 are disturbed. The disturbance in the magnetic flux lines induces a low frequency voltage or electromagnetic field (EMF) in the coil 86, which is incorporated into a signal output by the tubing feature sensor 80.

[0038] A prototype was constructed wherein a commercially available "casing collar locator" (CCL) was mounted within the TFL spool 52 for use as a component of the tubing feature sensor. Such a commercially available CCL is conventionally tripped downhole, such as on wireline. In a production embodiment, the electronic components of the tubing feature sensor 80 may be provided and positioned within a special compartment or cavity of the spool body. The spacing of the magnets 82, 84 and the tuning of the coil 86 in a production embodiment may be specially selected and empirically determined for optimal use with the particular type of tubing to be used with the tubing measurement and evaluation system 50.

[0039] The displacement sensors 60 generate signals in relation to the sensed axial displacement of the tubing. The tubing feature sensor 80 simultaneously generates a signal in relation to the changing local cross-sectional parameter of the tubing. These signals are output to a field computer 100 for analysis and interpretation. The analysis and interpretation, as further discussed below, may include both the present depth of the tubing string within a well, the identification of components mounted in the tubing string, the number of tubing segments, and the relative positions of the identified components within the tubing string.

[0040] The displacement sensors 60 work better when there is a relatively clean surface of the tubing string 30 for the rollers 62 to roll on. The replaceable rubber stripper 44 may be provided as a separate component above the spool 52 for scraping the tubing string 30 just before it enters the spool 52. The stripper 44 thereby helps clean the tubing string 30 when lowering the tubing string 30 into the well. One or more wire brush 51 is also provided at the lower end of the spool 52 in this embodiment, below the rollers 62, to help prevent debris from accumulating on or between the rollers 62 and for cleaning the tubing string 30 as it comes out of the bore hole. The one or more wire brush 51 may comprise a plurality of separate brushes that are mounted internally to the spool 52 and spaced circumferentially about the bore 55 of the spool 52. Alternatively, the wire brush 51 may comprise a continuous ring-shaped brush centered within the bore 55 of the spool 52 so that the tubing string 30 is scraped uniformly along its circumference when raising the tubing string 30 out of the well. The rubber stripper 44 at the upper end of the spool 52 and the one or more wire brush 51 at the lower end of the spool 52 below the rollers 62 are field-replaceable and may be relatively inexpensive.

[0041] FIG. 3 is a partially cut-away side view further detailing one of the roller type displacement sensors 60. The displacement sensor 60 includes a spring-loaded extension mechanism that includes a first extension member 70 slidably received on a second extension member 72. The second extension member 72 is coupled to the mounting plate 66. The extension mechanism may comprise a track, a piston-cylinder type arrangement, or other such arrangement whereby the second extension member 72 is moveable relative to the first extension member between an extended position and a retracted position, while remaining mechanically coupled to one another. In the example configuration of FIG. 3, the first and second extension members 70, 72 operate as a piston and cylinder, respectively. A spring 74 disposed between the first and second extension members 74 urges the first and second extension members 70, 72 toward the extended position, whereas a force applied by the tubing 31 in the TFL spool (FIG. 2) urges the extension mechanism toward a retracted position against an opposing spring force provided by the spring 74. The roller 62 is rotatably coupled to the first extension member 70 on an axle 63. The extension mechanism is shown in a partially-retracted position in FIG. 3, with the spring 74 having been compressed due to the force being applied by the tubing 31 to the roller 62. As the tubing 31 is moved in an axial direction, i.e. in a direction of a central axis of the tubing 31 into or out of the sheet of FIG. 3, any changes in the diameter of the tubing 31 along its length are accommodated by radial movement of the roller 62 on the spring-loaded extension mechanism, so that the roller 62 rolls along and maintains contact with an outer surface of the tubing 31. A sensor element 78 mounted in proximity to the roller 62 is responsive to a rotational displacement of the roller 62. The sensor element 78 is used to obtain a linear, axial displacement of the tubing 31 as a function of the rotational displacement of the roller 62. The non-sensor roller 62C (see FIG. 2) may be similarly constructed in terms of a spring-loaded mechanism, but without the need for any electronic sensor elements 78.

[0042] An optional roller pre-positioning mechanism is further illustrated in the example configuration of FIG. 3. The pre-positioning mechanism 75 allows a user to adjust the position of the roller 62 when the extension mechanism is in a relaxed state, e.g. with the tubing 31 removed from the bore of the TFL spool of FIG. 2. This adjustment correspondingly controls the amount by which the spring 74 is compressed when the tubing 31 is inserted within the TFL spool. In the example configuration, the pre-positioning mechanism 75 comprises an outer sleeve 76 threadedly engaged with an inner shaft 77. Rotating the outer sleeve 76, such as by hand or using a tool, causes a corresponding translational movement of the inner shaft 77, in a radial direction with respect to the spool bore. The inner shaft 77 is connected to the first extension member 70. Rotating the outer sleeve 76 in one direction thereby moves the roller 62 closer to a central axis of the TFL spool (FIG. 2), whereas rotating the outer sleeve 76 in the other direction conversely moves the roller 62 away from the central axis of the TFL spool.

[0043] One use of the roller pre-positioning mechanism is to adjust the starting position of the roller 62 for use with different diameters of tubing. To accommodate a larger diameter tubing, the user may adjust the pre-positioning mechanism 75 to move the roller 62 away from the central axis of the TFL spool, whereas to accommodate a smaller diameter tubing, the user may conversely adjust the pre-positioning mechanism 75 to move the roller 62 closer to the central axis of the TFL spool. Another use of the pre- positioning mechanism is to adjust the amount of pre-load of the spring 74 and the corresponding force of the roller 62 against the tubing 31. Increasing the amount of preload may help the roller 62 maintain contact with the tubing to prevent slippage and to closely track the outer profile of the tubing 31, whereas decreasing the amount of preload may reduce the wear on the roller 62. [0044] FIG. 4 is a side view of another example embodiment of the tubing measurement and evaluation system 50 having an optical displacement sensor 160 in lieu of the roller-type sensors of FIG. 2. The optical displacement sensor 160 obtains a linear displacement of the tubing 31 without physically contacting the tubing 31. In one configuration, the optical displacement sensor 160 includes an optoelectronic sensor element 162 to image texture in the tubing 31 and any matter accumulated on the tubing 31. The sensor element 162 may incorporate a light-emitting diode (LED) or infrared laser diode to illuminate a surface of the tubing 31. The illuminated surfaces, when lit at a grazing angle, cast distinct shadows. Images of these surfaces may be captured in continuous succession and compared with each other to determine how far the tubing 31 has moved. The optical displacement sensor 160 may also detect direction of movement, such that the signal generated by the optical displacement sensor 160 includes both the displacement and the direction of the displacement. The optical displacement sensor 160 may also include a mounting plate 166 for mounting to the TFL spool 52. In this example embodiment, there is one signal Si generated by the optical displacement sensor 160 and one signal S₂ generated by the tubing feature sensor 80.

[0045] FIG. 5 is a schematic diagram of an embodiment of the field computer 100 for receiving and interpreting the signals generated by the tubing measurement and evaluation systems of FIGS. 2 and 4. The field computer 100 includes a computer dock 102 for optionally connecting to a portable computer 120. The portable computer 120 may be a tablet computer or laptop computer, for example. A power supply may include a battery 104 and/or photovoltaic cell 106 for supplying power to the computer dock 102. The battery 104 may be rechargeable. The photovoltaic cell 106 converts radiant electromagnetic energy (e.g. sunlight) to electricity. The photovoltaic cell 106 may directly power the portable computer 120 or may be used to charge the battery 104. A printer 110 may also be provided for outputting the results of analysis performed by the computer 120. The results of the analysis may include a "tubing log" 112 as described further below. The tubing log 112 may graphically describe the length of the tubing positioned downhole and the relative positioning of various tubing features (e.g. joints and packers) within a tubing string. [0046] The portable computer 120 contains data analysis software 122 comprising computer usable program code. The software 122 may embody control logic specifically developed for use with the tubing measurement and evaluation system 50. This control logic may be used to analyze any number of signal input signals Si to S_n generated by the displacement and tubing feature sensors in the tubing measurement and evaluation system. In a broad sense, the control logic may analyze the signals to identify and/or locate variations in the cross-sectional property of the tubing string with the sensed linear displacement of the tubing string. Example control logic modules include a length/depth determination module 124 for determining well depth and/or tubing string length, a feature identification module 126 for identifying features of the tubing string, and a feature position determination module 128 for determining the position of the identified features either relative to the tubing string or to a fixed datum such as the rig floor. The data analysis software 122 may also include an electronic lookup table 130 embodying a predetermined correlation between various tubing features and their expected signal responses. As a tubing string is positioned downhole (See FIG. 1), the signal response from the displacement and tubing feature sensors are output to the computer 120, which invokes the various logic modules 124, 126, 128 to measure and evaluate the tubing string and features thereof.

[0047] The length/depth determination module 124 uses the displacement sensor signal(s) to monitor the relative displacement of the tubing string as it moves within the TFL spool (see FIG. 1). As the tubing string is lowered or raised within the well, the displacement sensor senses both the magnitude of the displacement and the direction of the displacement of the tubing string. A downward displacement of the tubing string increases a well depth measurement and a tubing length measurement. An upward displacement of the tubing string correspondingly decreases the well depth measurement and the tubing length measurement. When lowering and installing the tubing string into the well, there may be occasions when the tubing string is partially raised by some amount, such as to adjust the height of the tubing string for adding a tubing segment or stand, or to raise and re-lower the tubing string to correct the position of a tubular component mounted on the tubing string. Therefore, the ability to track the direction of the displacement allows any upward displacements to be subtracted from the depth and length measurements. Also, when removing a tubing string from the well, such as during workover operations, a decreasing depth measurement may also be tracked.

[0048] A datum or reference is selected for each of the length measurement and depth measurement. For example, the lower end of the tubing string, which is first to enter the well, may be selected as the starting point for the length measurement. The lower end of the tubing string may be sensed by the tubing feature sensor, triggering an automatic reference point to start measuring the tubing string. Alternatively, the moment of initial entry of the lower end of the tubing string may be sensed by the displacement sensor(s) when they begin sensing movement of the tubing string. For the depth measurement, any fixed location relative to ground may be selected as the datum. The rig floor or the TFL spool, for example, may be selected as the datum. If the rig floor is to be used as the datum for the depth measurement, a vertical spacing between the rig floor and the sensors in the TFL spool may be entered into the computer 120 by a well operator. This vertical distance may be added to the length measurement of the tubing string to obtain the depth measurement.

[0049] The feature identification module 126 is configured for identifying a tubing feature based on as few as one input signal, from the tubing feature sensor. A tubing feature in this context refers to any physical feature of the tubing string that may be distinguished from another physical feature of the tubing string. A first example of a tubing feature is a portion of a tubing segment having a constant cross-section. A second example of a tubing feature is an upset portion, flange, or collar of a tubing segment, which has a larger OD than the constant cross-section portion between upset portions. A third example of a tubing feature is a tubular component coupled to the tubing string other than a tubing segment. One examples of such a tubular component is a packer, which may be secured to an OD of a selected tubing segment and tripped downhole to seal an annulus between the casing and the tubing string in a selected formation zone. The identification of upset portions or collars at the end of each segment may be further used to count, i.e. tally, the tubing segments in the tubing string.

[0050] The feature identification module 126 receives a signal from the tubing feature sensor, which changes along the length of the tubing string, and analyzes the changing signal to identify a particular feature. Each feature may have a different characteristic signal response. For example, a straight section of a tubing segment may be expected to have a generally constant or uniform signal response from the tubing feature sensor. The signal from the tubing feature sensor is expected to change, such as to increase in magnitude, in transitioning from the straight section of the tubing segment to the upset portions of the tubing segment. The signal from the tubing feature sensor is expected to further change in proximity to a tubular component secured to the tubing string. For example, the characteristic response of the tubing feature sensor in proximity to a packer is expected to be distinct from the characteristic response of the tubing feature sensor in proximity to either a straight portion or upset portion of a tubing segment. The feature identification module 126 therefore analyzes these changes to distinguish between different features of the tubing string and/or to identify the specific features of the tubing string.

[0051] The feature identification module 126 may perform this analysis using as few as one signal provided by one tubing feature sensor. That is, the characteristic response from the tubing feature sensor may be sufficient in some cases to distinguish one type of feature from another feature, such as to distinguish a packer from an upset portion or to distinguish an upset portion from a straight section of tubing. However, the feature identification module 126 may be further informed by the signal from one or more displacement sensors. For example, a packer may have a characteristic length parameter in addition to a characteristic cross-sectional parameter. The length parameter may be determined by analyzing the signal from a displacement sensor. The length parameter of a particular feature may corroborate the identification of the component or further characterize the identified component. In one example, if the tubing feature sensor outputs a signal indicative of the cross-sectional parameter of a packer (e.g. the expected diameter, density, or volume of a packer), the length over which that characteristic signal is received may confirm or disconfirm that the sensed feature is a packer. In another example, two different features may have similar cross-sectional parameters but significantly different lengths, so a length determination may differentiate those two features. [0052] The predetermined correlation lookup table 130 embodying a predetermined correlation between tubing features and their expected signal response may be referenced by any of the logic modules. The predetermined correlation lookup table 130 may be referenced by the feature identification module 126 in distinguishing between features or identifying specific features of the tubing string under evaluation. The predetermined correlation lookup table 130 may include a set of different tubing features, such as straight- sections of tubing, upset portions of tubing, tubing collars, and one or more tubular components that may be secured to the tubing string. For each tubing feature in the table 130, a set of expected parameters may be provided. For example, each tubing feature in the table 130 may be uniquely associated with an expected cross-sectional parameter and/or length parameter, or specified ranges of these respective parameters.

[0053] The position determination module 128 may be invoked by the computer 120 to determine the position of an identified tubing feature. The position determination module uses the signal from at least one displacement sensor to determine the relative position of each feature identified by the feature identification module 126. The position may be expressed with respect to the tubing string. For example, the position of each feature may be expressed relative to a leading/lower end of the tubing string. Alternatively, the position of each feature may be expressed as a depth, such as with respect to the rig floor (FIG. 1). The position determination module 128 may be further used in the process of recording where various components are located downhole. For example, the location of a packer relative to the tubing string may be noted, and when the tubing string is in its final installed position, the precise depth of the packer within the well may be determined according to the packer's position on the tubing string.

[0054] Information contained within the tubing log 112 includes changes in the local cross-sectional parameter of the tubing string as the tubing string is moved within the TFL spool. The central pattern plotted in the tubing log 112 reflects the displacement and local cross-sectional parameter obtained by the spool-mounted sensors. The narrowest part of the plotted pattern in the tubing log 112 generally corresponds to straight sections of the tubing segments, which are numerous and constitute a large percentage of the total length of the tubing string. Portions of the tubing log 112 where the plotted pattern suddenly widens are referred to as "kicks" 115. Each kick 115 typically represents a feature other than a simple, straight section of tubing, at which the density, thickness, and/or volume of the tubing string at that location has increased. The kicks 115 may represent upset portions of tubing segments or tubular components such as packers mounted on the tubing string. The width of each kick 115 is related to the increased cross-sectional parameter, as reflected in the magnitude of the signal from the tubing feature sensor. The length of each kick 115 and spacing between kicks 115 is related to the displacement, and is reflected in the signal from the displacement sensor(s). Thus, the pattern plotted in the tubing log 112 may be proportional to the actual dimensions of the tubing string and features thereof.

[0055] FIG. 6 is an elevation view of the tubing measurement and evaluation system 50 of FIG. 2 along with a selected portion of a tubing log 112 corresponding to a portion of the tubing string 30 currently under evaluation. The tubing log 112 is shown being generated by the printer 110 for purpose of illustration, but could also be electronically generated as an image viewable on a display screen and stored as an electronic record. The tubing string 30 is shown here with a packer 34 supported on an OD of a segment 31 of the tubing string 30. A straight section of the tubing segment 31 is currently passing through the TFL spool 52. The packer 34 is above the TFL spool 52 and has not yet been registered on the tubing log 112. The rollers 62 of the displacement sensors 60A, 60B and the non-sensor roller 62C are in frictional contact with the tubing segment 31 so that as the tubing string 30 moves downward, the rollers 62 roll along an exterior of the tubing segment 31. With respect to the orientation of FIG. 6, a clockwise rotation of the roller 60 on the first displacement sensor 60A and a counter-clockwise rotation of the roller 60 on the second displacement sensor 60B generate signals each corresponding to an increasing (+) axial displacement of the tubing string 30. Simultaneously, the tubing feature sensor 80 outputs a relatively steady signal magnitude corresponding to the relatively constant cross-section of the tubing segment 31. This relatively constant signal output is manifested in a first portion 131 of the tubing log 112 having a correspondingly uniform width "w."

[0056] FIG. 7 is an elevation view of the tubing measurement and evaluation system 50, with the tubing string 30 having been lowered to where the packer 34 is positioned within the TFL spool 52. The packer is currently in proximity to the sensors 60A, 60B, 80. The rollers 62A, 62B of the respective spring-loaded displacement sensors 60A, 60B and the non-sensor roller 62C are urged to a retracted position in response to the rollers 62 having rolled from the straight section of the tubing segment 31 to the larger diameter of the packer 34. The tubing feature sensor 80 responds to the increased cross-section of the tubing string 30 in the location of the packer 34 with an increased signal magnitude. A second portion 134 of the tubing log 112 is a "kick" corresponding to the packer 34. The second portion 134 is visibly wider than the first section 131 corresponding to the narrower tubing segment 31.

[0057] The signals may be analyzed, as discussed in connection with FIG. 5, to identify that the first portion 131 of the tubing log 112 corresponds to a straight tubing segment section and that the second portion 134 of the tubing log 112 corresponds to the packer 34. These sections are optionally labeled on the tubing log 112 as "PCK" for packer and "TBNG" for tubing, respectively. The tubing feature identifications may alternatively be displayed on a display screen or stored and cataloged in electronic memory.

[0058] FIG. 8 is a flowchart generally outlining one example embodiment of a method for measuring and evaluating a tubing string as the tubing string is moved downhole, such as while installing production tubing in a well. Many variations of this method are also within the scope of the present disclosure, which are not all limited to the particular selection and order of steps in the flowchart FIG. 8. The steps in the flowchart may be further informed by the above discussion of the tubing measurement and evaluation system of FIGS. 1-7 and its manner of use.

[0059] According to step 200, an axial displacement of a tubing string is monitored. The tubing string may comprise tubing segments connected end-to-end and one or more components secured to the tubing string. The axial displacement of the tubing string is monitored with respect to a fixed location, such as at a specific sensor location in a BOP assembly. More specifically, the axial displacement of the tubing string may be measured by a displacement sensor mounted in proximity to the bore of a TFL spool in the BOP assembly. The displacement sensor may be, for example, a roller-type displacement sensor that frictionally engages an outer surface of the tubing string, or a non-contact displacement sensor, such as an optical displacement sensor.

[0060] According to step 202, a cross-sectional parameter "CX" of the tubing string is also measured. The cross-sectional parameter may be measured by a tubing feature sensor from about the same axial location with respect to the BOP assembly as the displacement sensor. The displacement sensor and tubing feature sensor are both preferably positioned in proximity to a through bore of a TFL spool in the BOP assembly. Although steps 200 and 202 are illustrated in series, the displacement measured in step 200 and the cross-sectional parameter measured in step 202 may be obtained simultaneously, in parallel.

[0061] A graphical representation of the measured cross-sectional parameter is plotted in step 204. For example, this pattern may be a tubing log, printed on paper or displayed as a graphical object on a computer display. The graphical representation may further include a description of identified features. The graphical object may be electronically stored in computer memory. The cross-sectional parameter may be plotted as a function of the sensed displacement, providing a to- scale representation of the tubing string and features thereof. The width of the plot may be related to the varying magnitude of the sensed cross-sectional parameter. Thus, features such as upset tubing portions or tubular components may be represented by wider kicks. The spacing between detected features of the tubing string and the spacing between kicks may likewise be to- scale.

[0062] A well depth and/or tubing string length is obtained according to step 206. The length or depth is related to the sensed displacement. The length of the tubing string may be determined as the net positive displacement of the tubing string as it advances beyond the fixed location in the BOP assembly. The well depth may expressed with respect to a datum, such as a wellhead or rig platform. The well depth may be computed, for example, as the length of the tubing string plus the difference in height between the datum and the fixed location at which the displacement is sensed.

[0063] Conditional step 208 involves dynamically sensing any appreciable changes in the cross-sectional parameter of the tubing string. Straight sections of a tubing segment are expected to be substantially uniform, and do not generally constitute an appreciable change in the cross-sectional parameter. However, other features, such as the upset ends of a tubing segment and tubular components secured to the tubing string, such as packers, generally do result in an appreciable increase in the cross-sectional parameter. Whether or not such an increase is detected at any given instant, the flowchart dynamically performs steps 200 and 202, thereby continually sensing of the displacement and the cross-sectional parameter.

[0064] If an increase in CX is detected at any given instant or location, conditional step 208 leads to generating a kick according to step 210. The kick represents the detection of a feature other than a straight, narrow section of a tubing segment. The kick may be plotted on paper or on a display screen. The location of the kick within the plot may be used to represent the location of the sensed feature with respect to the tubing string, which may be to-scale.

[0065] In step 212, the feature associated with the kick may be identified. In some cases, the feature may be identified as a function of the magnitude of the cross-sectional parameter CX, alone. For example, the value of CX for a particular feature may have a certain magnitude or narrow range of magnitude associated with it, which is sufficient to distinguish that feature from other features. In other cases, the feature may be identified as a function of both the cross-sectional parameter CX and the displacement "d." The magnitude of CX (corresponding to a width of the kick) may indicate a specific component or narrow the list of probable components, while the displacement d (corresponding to a length of the kick) may help narrow the possible features to one particular type of feature/component or to a particular sub-type. For example, the magnitude of CX may indicate the detection of a packer, whereas the length of the detected packer may further narrow the feature identification to a particular type or size of packer.

[0066] According to step 214, the relative position of the detected feature within the tubing string may be ascertained as a function of the displacement d. The tubing log may graphically position the kick at the same relative position as the detected feature is in the actual tubing string. [0067] As will be appreciated by one skilled in the art, aspects of the present invention may be embodied as a system, method or computer program product. Accordingly, aspects of the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment (including firmware, resident software, micro-code, etc.) or an embodiment combining software and hardware aspects that may all generally be referred to herein as a "circuit," "module" or "system." Furthermore, aspects of the present invention may take the form of a computer program product embodied in one or more computer readable medium(s) having computer readable program code embodied thereon.

[0068] Any combination of one or more computer readable medium(s) may be utilized. The computer readable medium may be a computer readable signal medium or a computer readable storage medium. A computer readable storage medium may be, for example, but not limited to, an electronic, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, or device, or any suitable combination of the foregoing. More specific examples (a non-exhaustive list) of the computer readable storage medium would include the following: an electrical connection having one or more wires, a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), an optical fiber, a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a computer readable storage medium may be any tangible medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device.

[0069] A computer readable signal medium may include a propagated data signal with computer readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A computer readable signal medium may be any computer readable medium that is not a computer readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device. [0070] Program code embodied on a computer readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing.

[0071] Computer program code for carrying out operations for aspects of the present invention may be written in any combination of one or more programming languages, including an object oriented programming language such as Java, Smalltalk, C++ or the like and conventional procedural programming languages, such as the "C" programming language or similar programming languages. The program code may execute entirely on the user's computer, partly on the user's computer, as a stand-alone software package, partly on the user's computer and partly on a remote computer or entirely on the remote computer or server. In the latter scenario, the remote computer may be connected to the user's computer through any type of network, including a local area network (LAN) or a wide area network (WAN), or the connection may be made to an external computer (for example, through the Internet using an Internet Service Provider).

[0072] Aspects of the present invention are described below with reference to flowchart illustrations and/or block diagrams of methods, apparatus (systems) and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by computer program instructions. These computer program instructions may be provided to a processor of a general purpose computer, special purpose computer, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, create means for implementing the functions/acts specified in the flowchart and/or block diagram block or blocks.

[0073] These computer program instructions may also be stored in a computer readable medium that can direct a computer, other programmable data processing apparatus, or other devices to function in a particular manner, such that the instructions stored in the computer readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.

[0074] The computer program instructions may also be loaded onto a computer, other programmable data processing apparatus, or other devices to cause a series of operational steps to be performed on the computer, other programmable apparatus or other devices to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide processes for implementing the functions/acts specified in the flowchart and/or block diagram block or blocks.

[0075] The flowchart and block diagrams in the Figures illustrate the architecture, functionality, and operation of possible implementations of systems, methods and computer program products according to various embodiments of the present invention. In this regard, each block in the flowchart or block diagrams may represent a module, segment, or portion of code, which comprises one or more executable instructions for implementing the specified logical function(s). It should also be noted that, in some alternative implementations, the functions noted in the block may occur out of the order noted in the figures. For example, two blocks shown in succession may, in fact, be executed substantially concurrently, or the blocks may sometimes be executed in the reverse order, depending upon the functionality involved. It will also be noted that each block of the block diagrams and/or flowchart illustration, and combinations of blocks in the block diagrams and/or flowchart illustration, can be implemented by special purpose hardware-based systems that perform the specified functions or acts, or combinations of special purpose hardware and computer instructions.

[0076] The corresponding structures, materials, acts, and equivalents of all means or steps plus function elements in the claims below are intended to include any structure, material, or act for performing the function in combination with other claimed elements as specifically claimed. The description of the present invention has been presented for purposes of illustration and description, but it is not intended to be exhaustive or limited to the invention in the form disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the invention. The embodiments were chosen and described in order to best explain the principles of the invention and the practical application, and to enable others of ordinary skill in the art to understand the invention for various embodiments with various modifications as are suited to the particular use contemplated.

Claims

CLAIMS What is claimed is:

1. An apparatus, comprising:

a spool including a through bore and one or more connectors for removably coupling the spool to a blowout preventer assembly;

a displacement sensor mounted to the spool in proximity to the through bore, the displacement sensor configured for sensing an axial displacement of a tubular member within the through bore of the spool and generating a signal in relation to the sensed axial displacement; and

a tubing feature sensor mounted to the spool in proximity to the through bore, the tubing feature sensor configured for sensing a cross-sectional parameter of the received tubular member in proximity to the tubing feature sensor and generating a signal in relation to the cross-sectional parameter of the received tubular member.

2. The apparatus of claim 1, wherein the tubing feature sensor is responsive to one or more of the cross-sectional parameters consisting of a thickness, a density, and a volume of the received tubular member in proximity to the tubing feature sensor.

3. The apparatus of claim 2, wherein the tubing feature sensor further comprises: first and second magnets separated by a coil and configured such that a difference in metal thickness or effective density of the tubular member adjacent to the two magnets induces a current spike in the coil.

4. The apparatus of claim 1, wherein the displacement sensor comprises:

a roller;

a biasing member configured to bias the roller radially inwardly into frictional engagement with the tubular member when received within the through bore; and

a sensor element configured for obtaining a linear displacement of the tubular member as a function of a rotational displacement of the roller.

5. The apparatus of claim 1, wherein the displacement sensor comprises:

a plurality of rollers circumferentially spaced along the through bore of the spool, wherein each roller is positioned to frictionally engage the tubular member when received within the through bore; and

a plurality of sensor elements each configured for obtaining a linear displacement of the tubular member as a function of a rotational displacement of a respective one of the rollers.

6. The apparatus of claim 1, further comprising:

a computer in electronic communication with the displacement sensor and the tubing feature sensor, the computer including control logic for identifying and locating variations in the cross-sectional property of the tubular member with the sensed linear displacement of the tubular member.

7. The apparatus of claim 6, further comprising:

a computer dock in electrical communication with the displacement sensor and the tubing feature sensor, the computer dock configured for removably connecting with the computer to place the computer in electronic communication with the displacement sensor and the tubing feature sensor.

8. The apparatus of claim 6, further comprising:

one or both of a portable rechargeable battery pack configured for supplying stored electrical energy to the computer dock and a photovoltaic cell configured for converting ambient electromagnetic radiation to electrical energy and supplying the electrical energy to the computer dock.

9. The apparatus of claim 1, further comprising:

a displacement sensor port defined by the spool, extending from an outer surface of the spool to the through bore of the spool;

a sensor mounting plate configured for removably mounting the displacement sensor to the spool and closing the displacement sensor port; and a sealing member configured for fluidly sealing between the spool and the sensor mounting plate.

10. A system, comprising

a blowout preventer (BOP) assembly in sealed fluid communication with a wellhead;

a spool coupled to the BOP assembly, the spool including a through bore in fluid communication with respective through bores of the BOP assembly and the wellhead such that a tubular member lowered into the wellhead through the BOP assembly passes through the spool;

a displacement sensor mounted to the spool in proximity to the through bore of the spool, the displacement sensor configured for sensing an axial displacement of the tubular member within the through bore of the spool and generating a signal in relation to the sensed axial displacement;

a tubing feature sensor mounted to the spool in proximity to the through bore, the tubing feature sensor responsive to a cross-sectional parameter of the received tubular member in proximity to the tubing feature sensor and configured for generating a signal in relation to the cross-sectional parameter of the received tubular member; and

11. The system of claim 10, wherein the BOP assembly comprises:

one or more sets of rams;

a stripper positioned above the one or more sets of rams and configured for circumferentially engaging the tubular member; and

wherein the spool is coupled to the BOP assembly above the one or more sets of rams and below the stripper.

12. A method, comprising:

sensing a linear displacement of a tubing string relative to a fixed location of a wellhead apparatus and generating a signal in response to the linear displacement;

sensing a change in a cross-sectional parameter of the tubing string in proximity to the fixed location and generating another signal in response thereto; and

identifying and locating variations in the cross-sectional property of the tubing string with the sensed linear displacement of the tubing string.

13. The method of claim 12, further comprising:

obtaining a well depth of the tubing string according to the sensed linear displacement of the tubing string.

14. The method of claim 12, further comprising:

identifying a tubing string component according to the value of the cross-sectional parameter at the location of the tubing string component.

15. The method of claim 14, further comprising:

confirming an identified tubing string component or identifying a particular subtype of the identified tubing string component according to the linear displacement in combination with the cross-sectional parameter.

16. The method of claim 12, further comprising:

obtaining a predetermined set of cross-sectional parameters for a plurality of tubing components stored in electronic memory; and

comparing the sensed cross-sectional parameter with the predetermined set of cross-sectional parameters to identify a component of the tubing string at the sensed linear displacement.

17. The method of claim 12, further comprising:

distinguishing between first and second tubing features according to a difference between the cross-sectional parameters.

18. The method of claim 12, further comprising:

distinguishing between a tubing segment in a tubing string and a tubular component secured to the tubing string according to a difference between the cross- sectional parameters of the tubing segment and the tubular component.

19. The method of claim 18, wherein the tubular component secured to the OD of the tubing string comprises a packer.

20. A computer program product including computer usable program code embodied on a computer usable storage medium, the computer program product comprising:

computer usable program code for receiving a first signal representative of a linear displacement of a tubing string relative to a fixed location of a wellhead apparatus; computer usable program code for receiving a second signal representative of a cross-sectional parameter of the tubing string in proximity to the fixed location; and

computer usable program code for interpreting the first and second signals to identify and locate variations in the cross-sectional property of the tubing string with the sensed linear displacement of the tubing string.