U.S. patent application number 13/759861 was filed with the patent office on 2014-08-07 for casing collar location using elecromagnetic wave phase shift measurement.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Douglas Hupp.
Application Number | 20140216734 13/759861 |
Document ID | / |
Family ID | 51258308 |
Filed Date | 2014-08-07 |
United States Patent
Application |
20140216734 |
Kind Code |
A1 |
Hupp; Douglas |
August 7, 2014 |
CASING COLLAR LOCATION USING ELECROMAGNETIC WAVE PHASE SHIFT
MEASUREMENT
Abstract
A method 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.
Inventors: |
Hupp; Douglas; (Anchorage,
AK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
51258308 |
Appl. No.: |
13/759861 |
Filed: |
February 5, 2013 |
Current U.S.
Class: |
166/255.1 |
Current CPC
Class: |
E21B 47/13 20200501;
E21B 47/09 20130101 |
Class at
Publication: |
166/255.1 |
International
Class: |
E21B 47/12 20060101
E21B047/12 |
Claims
1. A method for locating casing collars in a cased wellbore,
comprising: moving a well logging instrument coupled within a drill
string through the cased wellbore, the instrument including at
least one electromagnetic transmitter and at least two spaced apart
electromagnetic receivers; energizing the at least one
electromagnetic transmitter with alternating current; measuring a
phase difference between electromagnetic signals detected by each
of the at least two electromagnetic receivers; and identifying a
position of at least one casing collar when a change in the
measured phase difference is detected.
2. The method of claim 1 further comprising energizing the at least
one transmitter with alternating current at at least two different
frequencies and confirming that the measured phase difference
corresponds to at least one casing collar by comparing the phase
shift measurements made at each of the at least two different
frequencies.
3. The method of claim 2 wherein the at least two different
frequencies comprise 2 MHz and 400 KHz.
4. The method of claim 1 wherein the identifying position comprises
recording the measured phase difference in the well logging
instrument with respect to time, making a record at the surface of
position in the wellbore of the well logging instrument with
respect to time and correlating the recorded phase shift
measurements with respect to the position record with respect to
time.
5. The method of claim 1 wherein the identifying position comprises
detecting measurements of phase shift transmitted to the surface
from the well logging instrument.
6. The method of claim 1 further comprising moving the well logging
instrument into an uncased portion of the wellbore and detecting
phase shift measurements corresponding to formations surrounding
the wellbore.
7. The method of claim 1 further comprising energizing with
alternating current each of a plurality of spaced apart
electromagnetic transmitters disposed on the well logging
instrument, measuring phase shift between the at least two
receivers corresponding to the energizing of each of the plurality
of spaced apart electromagnetic transmitters.
8. The method of claim 7 further comprising energizing each of the
plurality of spaced apart transmitters with alternating current at
a plurality of frequencies and, measuring phase shift between the
at least two receivers corresponding to the energizing of each of
the plurality of spaced apart electromagnetic transmitters at each
of the plurality of frequencies.
9. The method of claim 1 further comprising using the measured
phase shift to determine a position of a casing shoe in the
wellbore.
10. A method for well logging, comprising: moving a well logging
instrument coupled within a drill string through the wellbore, the
instrument including at least one electromagnetic transmitter and
at least two spaced apart electromagnetic receivers, the wellbore
including a cased portion having jointed steel pipe therein and an
uncased portion therein; energizing the at least one
electromagnetic transmitter with alternating current; measuring a
phase difference between electromagnetic signals detected by each
of the at least two electromagnetic receivers; using the measured
phase difference to determine a resistivity of formations in the
uncased portion and; identifying a position of at least one casing
collar in the cased portion when a change in the measured phase
difference is detected.
11. The method of claim 10 further comprising energizing the at
least one transmitter with alternating current at at least two
different frequencies and confirming that the measured phase
difference in the cased portion corresponds to at least one casing
collar by comparing the phase shift measurements made at each of
the at least two different frequencies.
12. The method of claim 11 wherein the at least two different
frequencies comprise 2 MHz and 400 KHz.
13. The method of claim 10 wherein the identifying position
comprises recording the measured phase difference in the well
logging instrument with respect to time, making a record at the
surface of position in the wellbore of the well logging instrument
with respect to time and correlating the recorded phase shift
measurements with respect to the position record with respect to
time.
14. The method of claim 10 wherein the identifying position
comprises detecting measurements of phase shift transmitted to the
surface from the well logging instrument.
15. The method of claim 10 further comprising energizing with
alternating current each of a plurality of spaced apart
electromagnetic transmitters disposed on the well logging
instrument, measuring phase shift between the at least two
receivers corresponding to the energizing of each of the plurality
of spaced apart electromagnetic transmitters.
16. The method of claim 10 further comprising using the measured
phase shift to identify a position of a casing shoe in the
wellbore.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 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.
[0004] 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.
[0005] 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. Pat. No. 4,808,925 issued to Baird.
[0006] 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
[0007] 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.
[0008] Other aspects and advantages will be apparent from the
description and claims that follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 shows an example wellbore drilling system that may
include an electromagnetic propagation type resistivity measuring
instrument.
[0010] FIG. 2 shows an example electromagnetic propagation
instrument in more detail.
[0011] FIG. 3 illustrates the principle of the instrument of FIG. 2
as it pertains to locating casing collars.
[0012] FIG. 4 shows example logs using an instrument such as shown
in FIG. 2 for locating casing collars.
DETAILED DESCRIPTION
[0013] 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.
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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. Pat. 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
120A 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.
[0018] 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.
[0019] 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,
Tex.
[0020] 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 T1 through T5 may be disposed at selected positions
along the collar 122 exterior. Electromagnetic receivers R1, R2 may
be disposed at selected positions along the collar 122. In some
examples, the receivers R1, R2 may be disposed adjacent each other
to facilitate making measurements of changes in electromagnetic
fields between the receivers R1, R2.
[0021] 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 R1, 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 R1, R2. A non-limiting example of such circuitry is
described in the Clark et al. '122 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.
[0022] 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 R1, 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 R1,
R2. The foregoing is shown schematically in FIG. 3, wherein either
of two transmitters T1, 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 R1, R2.
[0023] FIG. 4 shows an example of data recorded in casing showing
the raw phase difference measurement using transmitter T1 in FIG. 3
at a frequency of 2 MHz at curve 44 and at a frequency of 400 KHz
at curve 46 using transmitter T1. 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.
[0024] 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.
[0025] 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).
[0026] 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.
* * * * *