SHIFT MEASUREMENT

Background

[0001] This disclosure relates generally to the field of locating the position of threaded couplings that join segments of steel pipe or "casing" inserted into a wellbore drilled through subsurface formations. Instruments used for such purpose are known as "casing collar locators." More particularly, the disclosure relates to casing collar location devices and techniques that use the principle of electromagnetic wave propagation.

[0002] Wellbores drilled through subsurface earthen formations may be completed by inserting and cementing in place therein one or more "strings" of steel pipe or "casing." Casing strings are inserted into the wellbore by assembling together end to end segments ("joints") of pipe to create the string. The joints are threadedly coupled together using external couplings called "collars" that thread to the exterior of adjacent longitudinal ends of casing joints. When the casing is fully inserted into the wellbore, it is desirable to be able to locate the axial position of one or more of the collars with respect to an axial length (wellbore depth) reference. Such reference may be the ground level at the Earth's surface, mean water level in offshore wellbores or other reference. The axial position of the one or more drill collars may be subsequently correlated to the depth in the subsurface of one or more formations for which further wellbore completion procedures may be performed.

[0003] One type of casing collar locator known in the art is electrically passive, in that no electrical power is used to operate the locator. Such casing collar locators may have there a magnet to magnetize the steel casing, and a wire coil to detect voltages induced by moving the magnet past the position of the casing collars. Such voltages may be induced by the change in thickness of metal in the axial vicinity of the casing collars. The detected voltage may be transmitted along an armored electrical cable whereupon an indication of the position of the casing collars may be inferred by an indicator of the detected voltage. See, for example, U.S. Patent No. 4,808,925 issued to Baird. [0004] There are instances in which a wellbore has casing only to a portion of its total depth; wellbore drilling may continue beyond the deepest point of the casing. Such drilling may include operating a drill string having one or more measuring instruments therein for determining properties of the formations outside the uncased, drilled wellbore. It is desirable to be able to locate casing collars in such circumstances without the need to remove the drill string and instruments in order to operate a conventional casing collar locator.

Summary

[0005] A method according to one aspect for locating casing collars in a cased wellbore includes moving a well logging instrument coupled within a drill string through the cased wellbore. The instrument includes at least one electromagnetic transmitter and at least two spaced apart electromagnetic receivers. The at least one electromagnetic transmitter is energized with alternating current. A phase difference between electromagnetic signals detected by each of the at least two electromagnetic receivers is measured. A position of at least one casing collar is determined when a change in the measured phase shift is detected.

[0006] Other aspects and advantages will be apparent from the description and claims that follow.

Brief Description of the Drawings

[0007] FIG. 1 shows an example wellbore drilling system that may include an electromagnetic propagation type resistivity measuring instrument.

[0008] FIG. 2 shows an example electromagnetic propagation instrument in more detail.

[0009] FIG. 3 illustrates the principle of the instrument of FIG. 2 as it pertains to locating casing collars.

[0010] FIG. 4 shows example logs using an instrument such as shown in FIG. 2 for locating casing collars. Detailed Description

[0011] FIG. 1 illustrates a wellsite system in which an electromagnetic propagation resistivity measuring instrument can be used. The wellsite can be onshore or offshore. In the example system in FIG. 1, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments of the drilling system can also use various forms of directional drilling equipment known in the art.

[0012] A drill string 12 is suspended within the borehole 11 and has a bottom hole assembly 100 which includes a drill bit 105 at its lower end. The surface system includes platform and derrick assembly 10 positioned over the borehole 11, the assembly 10 including a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string. The drill string 12 is suspended from a hook 18, attached to a traveling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string relative to the hook. As is well known, a top drive system (not shown) could be used instead of the kelly 17 and swivel 19.

[0013] In the present example, the surface system may further include drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, causing the drilling fluid to flow downwardly through the drill string 12 as indicated by the directional arrow 8. The drilling fluid exits the drill string 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows 9. In this well known manner, the drilling fluid lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.

[0014] A bottom hole assembly 100 of the illustrated embodiment may include a logging-while-drilling (LWD) instrument 120, a measuring-while-drilling (MWD) instrument 130, a rotary steerable directional drilling system and/or drilling motor 150, and drill bit 105. The LWD instrument 120 may be housed in a special type of drill collar, as is known in the art, and can include at least one well logging tool that measures resistivity of the formations 121 penetrated by the wellbore 11 using the principle of electromagnetic propagation. One non-limiting example of such an instrument is described in U.S. Patent No. 4,899,112 issued to Clark et al. and incorporated herein by reference. It will also be understood that more than one LWD and/or MWD instrument can be used, e.g., as represented at 120A. The LWD instrument 120 may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present example, the additional LWD instrument 120 A may include, without limitation, a formation dielectric constant measuring and/or include a nuclear magnetic resonance relaxometry instrument, acoustic well logging instrument, density instrument and/or neutron porosity instrument. The MWD tool 130 may also be housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool 130 may further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present example, the MWD tool 130 may include one or more of the following types of measuring devices: a weight-on- bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device. The MWD tool 130 may include a local communication device 132 such as a drilling fluid flow modulator of any type known in the art to communicate measurements made by the MWD tool 130 and/or LWD tools 120, 120A to a surface logging and control unit 25. The communication may be transmitted through the drilling fluid column and detected at the surface as changes in pressure of the drilling fluid, or in the case of using "wired" drill string components, may electromagnetically transmit data using an instrumented top sub 28. The tools 130, 120, 12A may also include internal memory or other data storage (not shown separately) in which measurements made by the various instruments in the tools 130, 120, 120A may be recorded and communicated to the surface logging and control unit 25 such as by electrical cable when the BHA 100 is withdrawn to the surface from the wellbore 11.

[0016] Certain portions of the wellbore 11 may have disposed and cemented therein a steel pipe of casing 7. The casing 7 may be assembled into a single conduit by threadedly coupling together end to end segments or "joints" of pipe using external couplings called "collars", shown at 7A. The lowermost end of the casing 7 may terminate in a casing "shoe" 7B. Drilling the wellbore 11 may continue below the casing shoe 7B into the formations 121.

[0017] In the present example, the casing collars 7A may be identified using an electromagnetic phase shift technique. The electromagnetic propagation instrument 120 may be, for example one used under the trademarks ARCVISION, ECOSCOPE or IMPULSE, which are trademarks of Schlumberger Technology Corporation, Sugar Land, Texas.

[0018] FIG. 2 shows a side view of the ARCVISION electromagnetic well logging instrument 120 in more detail. The instrument 120 may be housed in a drill collar 122 configured to be coupled into the drill string as explained with reference to FIG. 1. Electromagnetic transmitters Tl through T5 may be disposed at selected positions along the collar 122 exterior. Electromagnetic receivers Rl, R2 may be disposed at selected positions along the collar 122. In some examples, the receivers Rl, R2 may be disposed adjacent each other to facilitate making measurements of changes in electromagnetic fields between the receivers Rl, R2.

[0019] In the present example, alternating current is passed through any one or all of the transmitters T1-T5. In the present example, the alternating current may be either 2 MHz or 400 KHz frequency, although the exact frequency used is not a limit on the scope of the present disclosure. This induces an electromagnetic field around the tool 120. The two receivers Rl, R2 may be coupled to electronic circuitry 123 disposed inside the collar 122 to measure the phase shift of the electromagnetic signal between the two receivers Rl, R2. A non-limiting example of such circuitry is described in the Clark et al. Ί22 patent referred to hereinabove. The phase shift is related to the electromagnetic properties of the material around the tool 120. In some examples, the circuitry 123 may be configured to make phase shift and amplitude ratio measurements in uncased portions of the wellbore ("open hole") so that electrical properties, e.g., resistivity of the formations (121 in FIG. 1) can be determined.

[0020] When the drill string (12 in FIG. 1) is inserted into or withdrawn from the wellbore (11 in FIG. 1), the electromagnetic well logging instrument 120 will at some time travel through the casing (7 in FIG. 1). The presence of casing collars (7A in FIG. 1) changes the mass and distribution of the metal around the tool 120 resulting in a distortion in the electromagnetic field and resulting phase shift measured between the two receivers Rl, R2. When the tool 120 is in the casing the phase shift signal is dominated by the presence of the conductive metal of the casing. At the casing collars the mass of metal changes significantly from that in the middle of the joint or casing. This causes a change in the phase shift of the signal measured between the receivers Rl, R2. The foregoing is shown schematically in FIG. 3, wherein either of two transmitters Tl, T2 may be energized as explained, and a phase shift resulting from the electromagnetic properties of the materials surrounding the tool 120 takes place and may be measured from the signals detected by each of the receivers Rl, R2.

[0021] FIG. 4 shows an example of data recorded in casing showing the raw phase difference measurement using transmitter Tl in FIG. 3 at a frequency of 2 MHz at curve 44 and at a frequency of 400 KHz at curve 46 using transmitter Tl . The phase shifts may be compared with response of a long spacing detector of a LWD density instrument, shown at curve 42. On all three curves, 42, 44, 46, the casing shoe (7B in FIG. 1) and casing collars (7A in FIG. 1) are clearly identifiable as "spikes" in the phase difference measurements.

[0022] In some examples, more than one transmitter may be used to measure phase shift between the receivers. Any one or all of the transmitters T1-T5 in FIG. 2 may be used to provide corresponding phase shift measurements. More than one frequency of alternating current may be used for any one or more of the transmitters. As may be observed at curves 44 and 46 in FIG. 4, different frequencies may provide different raw values of phase difference and magnitude of the spikes associated with casing collars. However, the general appearance of the phase difference curve at casing collars may be substantially similar. Such appearance similarity may be used with reference to different transmitter spacings and alternating current frequencies to confirm that the changes in phase shift actually correspond to casing collars and not some other physical attribute of the casing, such as change in metal composition or thickness, etc.

[0023] By properly scaling the raw phase response on a log chart the measured depth of the casing collars can be identified. Scaling the phase difference response may be performed by using measurements transmitted to the surface from the MWD/LWD tools as explained with reference to FIG. 1, or may be made by using measurements recorded in the tools with respect to time, and correlating the time indexed recorded measurements to a time/depth record of the position of the various components of the drill string made at the surface in the logging and control unit (25 in FIG. 1).

[0024] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.