U.S. patent application number 14/301123 was filed with the patent office on 2014-12-25 for positioning techniques in multi-well environments.
The applicant listed for this patent is GYRODATA, Incorporated. Invention is credited to Graham Arthur McElhinney, Gary William Uttecht, John Lionel Weston, Eric Wright.
Application Number | 20140374159 14/301123 |
Document ID | / |
Family ID | 51176067 |
Filed Date | 2014-12-25 |
United States Patent
Application |
20140374159 |
Kind Code |
A1 |
McElhinney; Graham Arthur ;
et al. |
December 25, 2014 |
POSITIONING TECHNIQUES IN MULTI-WELL ENVIRONMENTS
Abstract
A method is provided to determine a distance, a direction, or
both between an existing first wellbore and at least one sensor
module of a drill string within a second wellbore being drilled.
The method includes using the at least one sensor module to measure
a magnetic field and to generate at least one first signal
indicative of the measured magnetic field. The method further
includes using the at least one sensor module to gyroscopically
measure an azimuth, an inclination, or both of the at least one
sensor module and to generate at least one second signal indicative
of the measured azimuth, inclination, or both. The method further
includes using the at least one first signal and the at least one
second signal to calculate a distance between the existing first
wellbore and the at least one sensor module, a direction between
the existing first wellbore and the at least one sensor module, or
both a distance and a direction between the existing first wellbore
and the at least one sensor module.
Inventors: |
McElhinney; Graham Arthur;
(Scotland, GB) ; Uttecht; Gary William; (Houston,
TX) ; Wright; Eric; (Aberdeenshire, GB) ;
Weston; John Lionel; (Christchurch, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GYRODATA, Incorporated |
Houston |
TX |
US |
|
|
Family ID: |
51176067 |
Appl. No.: |
14/301123 |
Filed: |
June 10, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61839311 |
Jun 25, 2013 |
|
|
|
Current U.S.
Class: |
175/45 |
Current CPC
Class: |
E21B 43/305 20130101;
E21B 7/04 20130101; E21B 47/024 20130101; E21B 47/0228 20200501;
E21B 47/00 20130101; E21B 47/092 20200501; E21B 44/005 20130101;
E21B 44/00 20130101 |
Class at
Publication: |
175/45 |
International
Class: |
E21B 44/00 20060101
E21B044/00; E21B 7/04 20060101 E21B007/04; E21B 47/00 20060101
E21B047/00 |
Claims
1. A method to determine a distance, a direction, or both between
an existing first wellbore and at least one sensor module of a
drill string within a second wellbore being drilled, the method
comprising: using the at least one sensor module to measure a
magnetic field and to generate at least one first signal indicative
of the measured magnetic field; using the at least one sensor
module to gyroscopically measure an azimuth, an inclination, or
both of the at least one sensor module and to generate at least one
second signal indicative of the measured azimuth, inclination, or
both; and using the at least one first signal and the at least one
second signal to calculate a distance between the existing first
wellbore and the at least one sensor module, a direction between
the existing first wellbore and the at least one sensor module, or
both a distance and a direction between the existing first wellbore
and the at least one sensor module.
2. The method of claim 1, further comprising controlling the drill
string using the calculated distance, the calculated direction, or
both.
3. The method of claim 2, wherein the drill string comprises a
rotary steerable drilling tool.
4. The method of claim 2, wherein controlling the drill string
comprises generating at least one control signal in response to the
calculated distance, the calculated direction, or both, and
transmitting the at least one control signal to a steering
mechanism of the drill string.
5. The method of claim 1, wherein using the at least one sensor
module to measure the magnetic field comprises using the at least
one sensor module to measure an axial field component of the
magnetic field along a longitudinal axis of the second
wellbore.
6. The method of claim 5, wherein the axial field component is
measured during drilling of the second wellbore.
7. The method of claim 1, further comprising: using the azimuth,
the inclination, or both with a model of the Earth's magnetic field
to estimate a contribution from the Earth's magnetic field to the
measured magnetic field; subtracting the contribution from the
measured magnetic field to calculate a corrected measured magnetic
field; and using the corrected measured magnetic field to calculate
at least one of the distance and the direction between the existing
first wellbore and the at least one sensor module.
8. A method for controlling a drill string spaced from an existing
first wellbore, the drill string drilling a second wellbore, the
method comprising: receiving at least one first signal indicative
of a magnetic field measured by at least a first sensor module of
the drill string; receiving at least one second signal indicative
of an azimuth, an inclination, or both measured by at least a
second sensor module of the drill string, the second sensor module
comprising at least one gyroscopic sensor; calculating a distance
between the existing first wellbore and the first sensor module, a
direction between the existing first wellbore and the first sensor
module, or both a distance and a direction between the existing
first wellbore and the first sensor module; and generating, in
response to at least one of the calculated distance and the
calculated direction, at least one control signal to be transmitted
to a steering mechanism of the drill string.
9. The method of claim 8, wherein the steering mechanism comprises
a rotary steerable tool.
10. The method of claim 8, further comprising transmitting the at
least one control signal to a steering mechanism of the drill
string.
11. The method of claim 8, wherein the at least one first signal is
indicative of a measured axial field component of the magnetic
field along a longitudinal axis of the second wellbore.
12. The method of claim 11, wherein the axial field component is
measured during drilling of the second wellbore.
13. The method of claim 8, further comprising: using the azimuth,
the inclination, or both with a model of the Earth's magnetic field
to estimate a contribution from the Earth's magnetic field to the
measured magnetic field; subtracting the contribution from the
measured magnetic field to calculate a corrected measured magnetic
field; and using the corrected measured magnetic field to calculate
at least one of the distance and the direction between the existing
first wellbore and the first sensor module.
14. A method for using a drilling tool to drill a second wellbore
along a desired path substantially parallel to a first wellbore,
the drilling tool comprising a steering mechanism, the method
comprising: (a) defining a first target position along a desired
path of the second wellbore, the first target position spaced from
a current position of the drilling tool by a first distance; (b)
performing magnetic ranging measurements and gyroscopic
measurements of an azimuth, an inclination, or both of the drilling
tool and using the magnetic ranging measurements and the gyroscopic
measurements to determine a second distance between the current
position of the drilling tool and the first wellbore; (c)
calculating a third distance between the first wellbore and the
desired path of the second wellbore; (d) calculating a target
sightline angle with respect to the desired path of the second
wellbore; (e) measuring a tool path direction with respect to the
first wellbore; (f) calculating a steering angle; (g) transmitting
a steering signal to the steering mechanism to control the steering
mechanism to adjust a tool path direction of the second wellbore by
the steering angle; and (h) actuating the steering mechanism to
move the drilling tool to a revised current position.
15. The method of claim 14, further comprising defining a second
target position along the desired path of the second wellbore, the
second target position spaced from the revised current position of
the drilling tool by the first distance, and iterating steps
(b)-(h).
16. The method of claim 14, wherein the drilling tool comprises a
first sensor module and a second sensor module, and the magnetic
ranging measurements and the gyroscopic measurements are made using
at least one of the first sensor module and the second sensor
module.
17. The method of claim 16, wherein the tool path direction is
measured using at least one of the first sensor module and the
second sensor module.
18. The method of claim 14, wherein calculating the third distance,
calculating the target sightline angle, and calculating the
steering angle are performed by a computer processor.
19. A method for gyro-assisted magnetic ranging relative to a first
wellbore using a rotary steerable drilling tool to drill a second
wellbore, the method comprising: (a) steering the drilling tool to
a position at which a magnetic field from an electromagnet in the
first wellbore can be detected by at least one sensor module of the
drilling tool; (b) performing a multi-station analysis to detect
magnetic biases from the drilling tool; (c) monitoring measurements
from a longitudinal axis magnetometer of the at least one sensor
module as a drill path of the second wellbore approaches the
electromagnet in the first wellbore; (d) making stationary magnetic
ranging survey measurements using the at least one sensor module;
(e) moving the electromagnet to a different position within the
first wellbore; (f) making magnetic ranging measurements and
further drilling the second wellbore in a trajectory that is
substantially parallel to the first wellbore; (g) making stationary
gyro survey measurements using the at least one sensor module and
using the stationary gyro survey measurements to determine a
separation and angle of approach of the at least one sensor module
to the first wellbore; and (h) using the stationary gyro survey
measurements to compute drilling commands to be performed by the
drilling tool and continuing to drill the second wellbore.
20. The method of claim 19, further comprising: (i) iterating steps
(f)-(h) until the magnetic field from the electromagnet is again
detected.
21. The method of claim 20, further comprising: (j) iterating steps
(c)-(h) for drilling subsequent sections of the second
wellbore.
22. The method of claim 19, wherein performing the multi-station
analysis occurs concurrently with steering the drilling tool.
23. The method of claim 19, wherein monitoring the measurements
comprises determining a slant range and a direction of the at least
one sensor module with respect to the electromagnet.
24. The method of claim 19, wherein determining the slant range and
the direction comprises using the detected magnetic biases.
25. The method of claim 19, wherein making stationary magnetic
ranging survey measurements comprises halting drilling of the
second wellbore upon the at least one sensor module reaching a
predetermined location with respect to the electromagnet.
26. The method of claim 19, wherein making stationary magnetic
ranging survey measurements comprises using the detected magnetic
biases to correct the stationary magnetic ranging survey
measurements.
Description
RELATED APPLICATIONS
[0001] This application claims the benefit of priority to U.S.
Provisional Appl. No. 61/839,311, filed Jun. 25, 2013 which is
incorporated in its entirety by reference.
BACKGROUND
[0002] 1. Field
[0003] This application relates generally to wellbore drilling and,
more particularly, to systems and methods for determining the
relative and absolute spatial positions of multiple subterranean
wellbores for drilling the wellbores in close proximity to each
other for a substantial part of their length, for the avoidance of
collisions between wellbores, or for interceptions of the wellbores
at all angles.
[0004] 2. Description of the Related Art
[0005] To determine the most accurate, absolute spatial position of
a wellbore, accurate survey instruments are desirable. Instrument
or measurement errors can result in errors in the spatial position
(e.g., an angular error of +/-0.3 degree can result in a positional
error of +/-5.24 meters over a 1000 meter length). In a two-well
scenario when both wells have a similar sized angular error, it is
possible for their relative displacement error to be as large as
10.48 meters over a 1000 meter length.
[0006] Conventional techniques for drilling a second wellbore in
proximity to a first wellbore (e.g., sidetracking) utilize a
magnetic sensor (e.g., a measurement while drilling or MWD system)
within the second wellbore to detect a magnetic field emanating
from the first wellbore (e.g., from a magnetic field source such as
an electromagnet, run in AC or DC mode, magnetized casing or a
"fish" within the first wellbore). Information generated by the MWD
system is transmitted to the surface (e.g., via mud pulse
telemetry) where an operator can use the information to control the
direction (e.g., steer) the drilling tool. However, uncertainties
associated with such conventional magnetic-based surveying
techniques can generate time-consuming challenges when drilling the
second wellbore in proximity to the first wellbore, particularly at
high inclinations. For example, if the target trajectory of the
second wellbore (e.g., the sidetrack wellbore) is not planned with
a significant safety margin and/or the bottom-hole assembly (BHA)
within the second wellbore does not include the proper amount of
non-magnetic spacing, then the MWD surveys of the second wellbore
can be compromised significantly by external magnetic interference
from the BHA, formation, magnetic mud, magnetic storms, target well
magnetism, leaving the second wellbore to effectively be drilled
blind. One possibility for monitoring the approach between a first
wellbore and a second wellbore can be to use the MWD sensors to
monitor external magnetic interference, and in close approach
situations to calculate the relative positions between the
sidetrack wellbore and the fish in the first wellbore. However,
calculating the relative position between wellbores can be
challenging when the inclination between the two wellbores exceeds
about 80 degrees.
SUMMARY
[0007] In certain embodiments, a method is provided to determine a
distance, a direction, or both between an existing first wellbore
and at least one sensor module of a drill string within a second
wellbore being drilled. The method comprises using the at least one
sensor module to measure a magnetic field and to generate at least
one first signal indicative of the measured magnetic field. The
method further comprises using the at least one sensor module to
gyroscopically measure an azimuth, an inclination, or both of the
at least one sensor module and to generate at least one second
signal indicative of the measured azimuth, inclination, or both.
The method further comprises using the at least one first signal
and the at least one second signal to calculate a distance between
the existing first wellbore and the at least one sensor module, a
direction between the existing first wellbore and the at least one
sensor module, or both a distance and a direction between the
existing first wellbore and the at least one sensor module.
[0008] In certain embodiments, a method is provided for controlling
a drill string spaced from an existing first wellbore, the drill
string drilling a second wellbore. The method comprises receiving
at least one first signal indicative of a magnetic field measured
by at least a first sensor module of the drill string. The method
further comprises receiving at least one second signal indicative
of an azimuth, an inclination, or both measured by at least a
second sensor module of the drill string. The second sensor module
comprises at least one gyroscopic sensor. The method further
comprises calculating a distance between the existing first
wellbore and the first sensor module, a direction between the
existing first wellbore and the first sensor module, or both a
distance and a direction between the existing first wellbore and
the first sensor module. The method further comprises generating,
in response to at least one of the calculated distance and the
calculated direction, at least one control signal to be transmitted
to a steering mechanism of the drill string.
[0009] In certain embodiments, a method is provided for using a
drilling tool to drill a second wellbore along a desired path
substantially parallel to a first wellbore. The drilling tool
comprises a steering mechanism. The method comprises defining a
first target position along a desired path of the second wellbore.
The first target position is spaced from a current position of the
drilling tool by a first distance. The method further comprises
performing magnetic ranging measurements and gyroscopic
measurements of an azimuth, an inclination, or both of the drilling
tool and using the magnetic ranging measurements and the gyroscopic
measurements to determine a second distance between the current
position of the drilling tool and the first wellbore. The method
further comprises calculating a third distance between the first
wellbore and the desired path of the second wellbore. The method
further comprises calculating a target sightline angle with respect
to the desired path of the second wellbore. The method further
comprises measuring a tool path direction with respect to the first
wellbore. The method further comprises calculating a steering
angle. The method further comprises transmitting a steering signal
to the steering mechanism to control the steering mechanism to
adjust a tool path direction of the second wellbore by the steering
angle. The method further comprises actuating the steering
mechanism to move the drilling tool to a revised current
position.
[0010] In certain embodiments, a method is provided for
gyro-assisted magnetic ranging relative to a first wellbore using a
rotary steerable drilling tool to drill a second wellbore. The
method comprises steering the drilling tool to a position at which
a magnetic field from an electromagnet in the first wellbore can be
detected by at least one sensor module of the drilling tool. The
method further comprises performing a multi-station analysis to
detect magnetic biases from the drilling tool. The method further
comprises monitoring measurements from a longitudinal axis
magnetometer of the at least one sensor module as a drill path of
the second wellbore approaches the electromagnet in the first
wellbore. The method further comprises making stationary magnetic
ranging survey measurements using the at least one sensor module.
The method further comprises moving the electromagnet to a
different position within the first wellbore. The method further
comprises making magnetic ranging measurements and further drilling
the second wellbore in a trajectory that is substantially parallel
to the first wellbore. The method further comprises making
stationary gyro survey measurements using the at least one sensor
module and using the stationary gyro survey measurements to
determine a separation and angle of approach of the at least one
sensor module to the first wellbore. The method further comprises
using the stationary gyro survey measurements to compute drilling
commands to be performed by the drilling tool and continuing to
drill the second wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] Various configurations are depicted in the accompanying
drawings for illustrative purposes, and should in no way be
interpreted as limiting the scope of the systems or methods
described herein. In addition, various features of different
disclosed configurations can be combined with one another to form
additional configurations, which are part of this disclosure. Any
feature or structure can be removed, altered, or omitted.
Throughout the drawings, reference numbers may be reused to
indicate correspondence between reference elements.
[0012] FIG. 1 schematically illustrates an example target box in a
cross-sectional view in a plane generally perpendicular to a first
wellbore (e.g., a target well) and to a second wellbore (e.g., a
drilling well) generally parallel to the first wellbore in
accordance with certain embodiments described herein.
[0013] FIG. 2A schematically illustrates an example electromagnet
with its magnetic field shown by magnetic flux lines in accordance
with certain embodiments described herein.
[0014] FIG. 2B schematically illustrates an example extended range
magnetic tool (XMT) comprising an electromagnet compatible with
certain embodiments described herein.
[0015] FIG. 3A schematically illustrates an example cross-sectional
view of the cross-axial magnetic flux pattern in a plane generally
perpendicular to the first wellbore (e.g., target well) and to the
second wellbore (e.g., drilling well) in accordance with certain
embodiments described herein.
[0016] FIG. 3B shows a magnetic map of the magnetic field magnitude
(in gauss) of the XMT of FIG. 2B in a horizontal plane
perpendicular to a longitudinal axis of the XMT.
[0017] FIG. 4 is a schematic diagram of the magnetic field of an
example electromagnetic target between two casing joints of a
target well in accordance with certain embodiments described
herein.
[0018] FIG. 5A is a flow diagram of an example method to determine
a distance, a direction, or both between an existing first wellbore
and at least one sensor module of a drill string within a second
wellbore being drilled in accordance with certain embodiments
described herein.
[0019] FIG. 5B is a flow diagram of an example method for
controlling a drill string spaced from an existing first wellbore,
the drill string drilling a second wellbore, in accordance with
certain embodiments described herein.
[0020] FIG. 6A schematically illustrates the positions of a number
of standard magnetic ranging survey measurements to be taken along
a target box 570 meters long.
[0021] FIG. 6B schematically illustrates the positions of a fewer
number of gyro-assisted ranging survey measurements to be taken
along the target box of FIG. 6A in accordance with certain
embodiments described herein.
[0022] FIG. 7 schematically illustrates a comparison between
balanced electromagnetic vectors and unbalanced electromagnetic
vectors due to BHA interference.
[0023] FIG. 8A schematically illustrates an example configuration
of a drilling tool configured to drill a second wellbore (e.g.,
drilling well) along a desired path parallel to and in close
proximity to a first wellbore (e.g., target well) in accordance
with certain embodiments described herein.
[0024] FIG. 8B is a flow diagram of an example method of drilling a
second wellbore (e.g., drilling well) along a desired path parallel
to and in close proximity to a first wellbore (e.g., target well)
in accordance with certain embodiments described herein.
[0025] FIG. 9 schematically illustrates an example measurement of
the tool path direction (.alpha.) with respect to the first
wellbore path using the first sensor module and the second sensor
module in accordance with certain embodiments described herein.
[0026] FIG. 10 schematically illustrates an example progression of
the drill string using multiple iterations of the example method of
FIG. 8B in accordance with certain embodiments described
herein.
[0027] FIG. 11 schematically illustrates the first and second
wellbores in a plan view from above the Earth's surface in a
direction perpendicular to the Earth's surface and in a section
view in a direction parallel to the Earth's surface.
[0028] FIG. 12A schematically illustrates the magnetic field
generated by an electromagnet in accordance with certain
embodiments described herein.
[0029] FIG. 12B schematically illustrates an SAGD configuration in
which a portion of the first wellbore is in proximity to and
parallel to a portion of the second wellbore.
[0030] FIG. 12C schematically illustrates a horizontal to vertical
interception configuration in which the switch pattern occurs at
the point of closest approach of the first wellbore to the second
wellbore.
[0031] FIG. 13A schematically illustrates an example configuration
including a table of example measured values of the various
parameters of the magnetic field from the electromagnet in
accordance with certain embodiments described herein.
[0032] FIG. 13B schematically illustrates an example well
paralleling configuration including a table of example measured
values of the various parameters of the magnetic field from the
electromagnet 60 in accordance with certain embodiments described
herein.
[0033] FIG. 13C schematically illustrates an example horizontal to
vertical interception configuration including a table of example
measured values of the various parameters of the magnetic field
from the electromagnet in accordance with certain embodiments
described herein.
[0034] FIG. 14 is a flow diagram of an example method for
gyro-assisted magnetic ranging in the context of SAGD drilling
using a rotary steerable drilling tool in accordance with certain
embodiments described herein.
DETAILED DESCRIPTION
[0035] Although certain configurations and examples are disclosed
herein, the subject matter extends beyond the examples in the
specifically disclosed configurations to other alternative
configurations and/or uses, and to modifications and equivalents
thereof. Thus, the scope of the claims appended hereto is not
limited by any of the particular configurations described below.
For example, in any method or process disclosed herein, the acts or
operations of the method or process may be performed in any
suitable sequence and are not necessarily limited to any particular
disclosed sequence. Various operations may be described as multiple
discrete operations in turn, in a manner that may be helpful in
understanding certain configurations; however, the order of
description should not be construed to imply that these operations
are order-dependent. Additionally, the structures, systems, and/or
devices described herein may be embodied as integrated components
or as separate components. For purposes of comparing various
configurations, certain aspects and advantages of these
configurations are described. Not necessarily all such aspects or
advantages are achieved by any particular configuration. Thus, for
example, various configurations may be carried out in a manner that
achieves or optimizes one advantage or group of advantages as
taught herein without necessarily achieving other aspects or
advantages as may also be taught or suggested herein.
[0036] Certain embodiments described herein provide methods to
determine the positions of multiple wells (e.g., primary and
secondary wells) using a high-accuracy multi-dimensional indexed
Earth's rate gyroscope in conjunction with magnetic measurements.
Certain embodiments may be used in various applications, including
but not limited to, twin wells for steam assisted gravity drainage
(SAGD), in-fill drilling, target interceptions, coal bed methane
(CBM) well interceptions, relief well drilling, syngas well
interceptions, river crossings, and many others. Certain
embodiments described herein overcome the limitations of multi-well
positioning that uses only standard magnetic ranging, but may
equally apply to sonic, acoustic, radar, thermal, gravity and
ranging that uses any part of the electromagnetic spectrum.
[0037] Certain embodiments described herein advantageously increase
safety and reduce costs associated with all ranging including
magnetic ranging at all angles of drilling by using gyro-assisted
magnetic ranging which combines information obtained from
measurement while drilling (MWD) and gyro while drilling (GWD)
surveying. Gyro-assisted magnetic ranging can eliminate the need to
run wireline conveyed gyros, thereby saving considerable expense.
Gyro-assisted magnetic ranging can allow data to be collected
frequently while the drilling progresses, which can reduce (e.g.,
minimize) the risk of unintentionally intercepting the first
wellbore without slowing the drilling process. Gyro-assisted
magnetic ranging can be used in conjunction with rotary steerable
drilling to automate the drilling process by reducing the role of a
human operator in controlling (e.g., steering) the drill string
while drilling the second wellbore. Additionally, using
gyro-assisted magnetic ranging can provide more accuracy and
flexibility in sidetrack trajectories since any attitude is
available (e.g., there is no longer a need to steer by inclination
only), thereby improving efficiency in drilling operations. For
example, a passive MWD ranging system and method can use both the
output of MWD magnetic sensors and the directional information
calculated from an all-inclination GWD system. Certain such systems
and methods can allow the calculation of the spatial relationship
(e.g., distance and direction) between the second wellbore and the
first wellbore, even at or near 90 degrees inclination. In such
configurations in which the second wellbore and the first wellbore
are at or near 90 degrees inclination and are not parallel to one
another, a high inclination gyro can be used to calculate the
azimuth for passive ranging calculations. In certain circumstances,
an electromagnetic target is placed in the first wellbore for
active ranging. For passive ranging, a permanent magnet target can
be placed in the first wellbore. In certain other circumstances in
which a target cannot be placed in the first wellbore, a single
entry ranging technique can be used, which utilizes passive ranging
from the detected remnant magnetization in the first (e.g., target)
wellbore casing (e.g., from previous MPI magnetism). Alternatively,
active AC magnetic ranging in which an AC current is generated in
the target well using an electromagnet in the drilling well may be
used (see, e.g., US2004/0069721A1). Besides being used to achieve
an intersection of the second wellbore with the first wellbore, the
systems and methods described herein can also be used to avoid
intersection by allowing the positional relationship between the
second wellbore and the first wellbore to be continuously monitored
until the collision risk has passed.
[0038] Accurate wellbore positioning information at all angles can
advantageously be provided by a gyroscopic system (e.g., a
multi-dimensional Earth's rate gyroscope; a three-dimensional
indexed Earth's rate gyroscope) which can provide measurements with
errors much less than those from magnetic survey systems. Even so,
all instruments in a wellbore (e.g., a bottom-hole assembly or BHA)
may suffer from some misalignment due to the tortuosity of the
wellbore or due to the lack of survey density in a tortuous
wellbore. See, e.g., "Continuous Direction and Inclination
Measurements Lead to an Improvement in Wellbore Positioning," E. J.
Stockhausen, W. G. Lesso, SPE/IADC 79917, 19 Feb. 2003. Magnetic
survey instruments also may be adversely affected by magnetic
interference from the BHAs, adjacent wellbores, magnetic
formations, magnetic mud, and magnetic storms.
[0039] As an example of the effects of errors in these
measurements, consider a "well twinning" scenario in which a second
wellbore 40 (e.g., a drilling well) is drilled to be generally
parallel to a first wellbore 10 (e.g., a target well). It is common
practice in well twinning to define at least one target box 50 to
be intercepted by the second wellbore 40, with the target box 50
positioned in a production target region and spaced away from the
first wellbore 10. FIG. 1 schematically illustrates an example
target box 50 in a cross-sectional view in a plane generally
perpendicular to a first wellbore 10 (e.g., a target well) and to a
second wellbore 40 (e.g., a drilling well) generally parallel to
the first wellbore 10. The absolute position of the first wellbore
10 can be unimportant. The target box 50 can follow the profile
(e.g., trajectory) of the first wellbore 10, paralleling the first
wellbore 10 along its length. Target sizes may vary and FIG. 1
schematically illustrates an example target box 50 that is 1 meter
in a high side direction by 2 meters in a right side direction, and
offset from the first wellbore 10 by 5 meters in the high side
direction and by 1 meter in the right side direction to allow for
the possibility of any re-drills. The target box 50 is a relative
target, relative to the first wellbore position. If centered, as a
result of a 0.3 degree azimuth error, the second wellbore 40 could
drift out of the 1 meter by 2 meters target box 50 over a measured
depth of approximately 190 meters.
Ranging Systems and Methods
[0040] A residual error can grow with distance in the absolute
position of multiple wellbores, so ranging systems and methods can
be used to provide the relative position of one wellbore related to
the other or to provide the range (e.g., distance) between the two
wellbores.
[0041] Some existing ranging techniques use magnetism as a method
to determine the position of another wellbore. These magnetic
ranging techniques can include active ranging (e.g., using a
magnetic field generated, either AC or DC, by an electromagnet
within the first wellbore), and passive ranging (e.g., using an
existing magnetic field). See, e.g., "Surveying of Subterranean
Magnetic Bodies from an Adjacent Off-Vertical Borehole," F. J.
Morris, R. L. Waters, G. F. Roberts, U.S. Pat. No. 4,072,200, Feb.
7 1978; "Downhole Combination Tool," R. L. Waters, et al., EP Pat.
No. 0366567, 30 Oct. 1989; "Method of Determining the Coordinates
and Magnetic Moment of a Dipole Field Source," B. M. Smirnov,
Izmeritel'naya Tekhnika, No. 6, June 1990.
[0042] In active magnetic ranging, one or more electromagnets 60
may be used as a magnetic field source in the first wellbore 10
(e.g., target well). Thus, active ranging can utilize access to the
first wellbore 10. FIG. 2A schematically illustrates an example
electromagnet 60 with its magnetic field 62 shown by magnetic flux
lines. The example electromagnet 60 can be positioned in the first
wellbore 10 (e.g., target well) and can output a DC magneto-static
field in the first wellbore 10 in response to a current flowing
through the electromagnet 60. FIG. 2B schematically illustrates an
example "extended range magnetic tool" (XMT) comprising an
electromagnet 60 compatible with certain embodiments described
herein. The example tool of FIG. 2B is separated into three
sections (e.g., sondes 60a, 60b, 60c) which can be coupled together
and can be coupled to a wireline cable head (e.g., using a standard
Gearhart connection as a cable head adapter) to be inserted into
the first wellbore. An example XMT compatible with certain
embodiments described herein is available from TSL Technology Ltd.
of Ropley, Alresford, Hampshire, United Kingdom.
[0043] FIG. 3A schematically illustrates an example cross-sectional
view of the cross-axial magnetic flux pattern in a plane generally
perpendicular to the first wellbore 10 (e.g., target well) and to
the second wellbore 40 (e.g., drilling well). FIG. 3B shows a
magnetic map of the magnetic field magnitude (in gauss) of the XMT
of FIG. 2B in a horizontal plane perpendicular to a longitudinal
axis of the XMT. This magnetic field 62 may be detected by standard
or adapted (resealed) magnetometers, which can be included as part
of a MWD sensor module or as part of a ranging-dedicated survey
package in the BHA (e.g., between a steering mechanism and a drill
bit of a rotary steerable drilling tool) of the second wellbore 40
(e.g., the drilling well or the well being drilled). Due to the
axially symmetrical nature of the magnetic field 62 around the
electromagnet 60 of the first wellbore 10, it is possible to
determine the distance of the magnetometers in the second wellbore
40 to the electromagnet 60 from the intensity of the field and the
magnetic flux's axial angle, as these two measurements are unique
at a particular distance. The direction to the electromagnet 60 can
be determined from the cross-axial component of the magnetic field
62 since the cross-axial component is aligned towards or away from
the electromagnet 60. For example, as shown in FIGS. 2A, 3A, and
3B, the magnetic field 62 is generally cylindrically symmetric
about the long axis of the electromagnet 60 (e.g., the magnetic
field intensity and angle have the same values along a circle
centered on the electromagnet 60), and the magnetic field angle
(e.g., the angle .theta. of the magnetic flux lines with respect to
the long axis of the electromagnet) and the magnetic field
intensity are dependent on the radial distance from the
electromagnet 60 and on the position of the plane perpendicular to
the long axis. The cross-axial components (H.sub.xi, H.sub.yi) of
the magnetic field 62 can be used to determine the radial distance
of the magnetometers relative to the long axis of the electromagnet
60 and the position of the magnetometers along the long axis of the
electromagnet 60.
[0044] This technique can be used in applications in which the
second wellbore 40 is drilled to be parallel to the first wellbore
10 (e.g., well twinning for SAGD), for applications in which the
second wellbore 40 is intended to avoid the first wellbore 10, or
for applications in which the second wellbore 40 is intended to
intercept the first wellbore 10 (e.g., horizontal to vertical
interception, such as in the case of CBM the electromagnet may be
lowered down the near vertical target well). For example, an
electromagnet 60 can be pushed along the first wellbore 10 (e.g.,
target well) using a tractor, coil tubing, or other means. The
electromagnet 60 can be positioned in the center of a casing joint
of the first wellbore 10, rather than near the ends of the casing
joint, since the casing collars at the joint ends have
substantially more metal and can therefore distort the magnetic
field in an asymmetric way. Thus, the magnetic ranging surveys can
be taken away from the collars to prevent (e.g., reduce, minimize)
this distortion. For example, FIG. 4 is a schematic diagram of the
magnetic field 62 of an example electromagnetic target between two
casing joints of a target well. Standard methods include the use of
two survey measurements taken at each casing joint, one with the
electromagnet 60 energized in a positive mode and another with the
electromagnet 60 energized in a negative mode. The difference
between the readings can provide a measurement of two times the
strength of the magnetic field 62 from the electromagnet 60. In
other situations, the survey measurements taken at each casing
joint can include one with the electromagnet 60 energized or "on"
and another with the electromagnet 60 not energized or "off".
However, there can be residual magnetic interference in the casing
(e.g., from previous magnetic particle inspection or MPI of the
casing, or by magnetization of the casing due to previous uses of
the electromagnet 60) that can distort the null field. The survey
measurements can be taken about every 11 to 13 meters (e.g., the
casing joint length) along the second wellbore 40, as indicated in
FIG. 4. The time for taking such survey measurements depends on the
transmission system used. For example, if electromagnetic (EM)
pulse telemetry is used, the time for transmitting the information
from the survey measurements to an above-surface location can be a
significant fraction of the total time for taking a mud pulsed
survey. However, the faster technique of electromagnetic telemetry
can significantly shorten the total time for taking the survey.
[0045] The first wellbore 10 may be cased with steel or other
materials that can affect the magnitude and/or direction of the
magnetic field 62. For example, due to its magnetic permeability,
the effect of steel can be to absorb some of the magnetic field 62.
See, e.g., "Method and Apparatus for Measuring Distance and
Direction by Movable Magnetic Field Source," A. F. Kuckes, Vector
Magnetics, Inc., U.S. Reissue Pat. No. 36,569, U.S. Pat. No.
5,485,089, filed 8 Oct. 1993. In addition, the position of the
electromagnet 60 in the casing, if non-centered, may cause an
asymmetry in the magnetic field 62 outside the casing. This effect
can be difficult to model for, hence it can be a source of error in
the results especially with weak electromagnets.
[0046] These detrimental effects can be somewhat negated in active
ranging by the use of a very powerful XNT type electromagnet 60.
For example, a sufficiently powerful electromagnet 60 can
magnetically saturate the casing and can thereby create a useful
effect. A magnetically saturated casing may not absorb nor inhibit
the magnetic flux, so the magnetic flux can therefore pass through
uninhibited. There may be some reduction in the strength of the
near field due to the absorption from the casing, amounting to a
reduction in the magnetic field magnitude of a few percent. The
effect can also slightly increase the pole separation that is
observed outside the casing, which may enhance the far field.
Casing diameter, thickness, and the permeability of the casing
material may all have an influence as is understood by persons
skilled in the art. Casings often can have collars to reinforce the
thin walls at the threads where adjacent casing sections are
coupled to one another. Such collars can create a distortion in the
symmetry of the magnetic field 62 (e.g., lack of axial symmetry in
the magnetic field 62) created by the electromagnet 60. Although
this effect can be considered to be local, near field measurements
can be avoided around these areas. In addition, it can be helpful
to ensure that the electromagnet 60 is positioned at the central
axis of the casing joint to avoid erroneous ranging results at this
position due to the cross axial component being near zero.
[0047] Another technique that can be used for active magnetic
ranging of adjacent wells is the use of permanent magnets placed in
a bit sub. See, e.g., "Rotating Magnetic Ranging--A New Guidance
Technology," A. G. Nekut, A. F. Kuckes, R. G. Pitzer 8th SPE, One
Day Conference on Horizontal Well Technology, 7 Nov. 11, 2001;
"Rotating Magnet for Distance and Directional Measurements from a
First Borehole to a Second Borehole," A. F. Kuckes, U.S. Pat. No.
5,589,775. These permanent magnets can rotate with the bit (within
the second wellbore 40) and can create a low frequency (e.g., at
the revolution per minute of the bit) alternating magnetic field
62. The maximum amplitude of the signal (measured from within the
first wellbore 10) is when the magnets are coplanar to the
cross-axial component of the first wellbore 10. From this maximum
amplitude, it can be possible to derive the distance between the
second wellbore 40 and the first wellbore 10.
[0048] When the measured maximum negative magnetic field magnitude
is subtracted from the measured maximum positive magnetic field
magnitude, the resultant vector can be expressed as an angle on the
cross-axial (target) plane. This vector can indicate the direction
to the second wellbore 40. A distance and strength of the source
can be derived by using the half-height-width of the wave and a
gradient of the overall ellipse of the waveforms can indicate
distance. See, e.g., "A Gyro-Oriented 3-Component Borehole
Magnetometer for Mineral Prospecting, With Examples of its
Application," W. Bosum, D. Eberle, H. J. Rehli, "Geophysical
Prospecting 36," pp. 933-961, 1988; "Case Histories Demonstrate a
New Method for Well Avoidance and Relief Well Drilling," G.
McElhinney, R. Sognnes, B. Smith, SPE/IADC 37667. It is noted that
the signal can be much weaker inside a casing.
[0049] Other active magnetic ranging techniques may include devices
that output an AC electromagnetic field from the second wellbore 40
to create a current in the first wellbore 10 (e.g., the target
wellbore). As current flows through the first wellbore casing,
along the BHA and formation boundaries, it can thus create other
magnetic fields. The BHA current and magnetism is usually fairly
constant and may be removed by rotation shots. Formation boundary
effects, non-homogeneous formations and anisotropy can be more
problematic to solve for. Generally, the more homogeneous the
formations are, the easier it is to model these effects out.
[0050] A technique using a single wire run in the first wellbore 10
and anchored at its foot can be used. A DC current can be passed
through the wire to generate a circular magnetic field 62 in cross
section. When the current dissipates through the anchor point into
the casing, an unknown magnetic field can be created in the
opposite direction to the magnetic field created by the wire. The
magnitude of the current and the distance along the casing the
current travels are dependent on the conductivity of the casing
versus the conductivity of the formation. In high resistive, low
conductive formations (e.g., like the oil sands), this reverse
current generates a reverse magnetic field that can travel further
up the casing, having a detrimental effect on results above the
anchor point.
[0051] The aforementioned active magnetic ranging techniques can
have limitations that can cause relative and absolute positional
errors, which can be compounded by a reaction to these errors. For
example, as mentioned in "A Gyro-Oriented 3-Component Borehole
Magnetometer for Mineral Prospecting, With Examples of its
Application," W. Bosum, D. Eberle, H. J. Rehli, "Geophysical
Prospecting 36," pp. 933-961, 1988 and "Case Histories Demonstrate
a New Method for Well Avoidance and Relief Well Drilling," G.
McElhinney, R. Sognnes, B. Smith, SPE/IADC 37667, there can be an
issue determining the solution for the 180 degree ambiguity, which
can result in the position of the second wellbore 40 being
misinterpreted as left of the first wellbore 10 instead of right,
or vice versa. This ambiguity may result in the second wellbore 40
being steered in the wrong direction and leading to an exit from
the target box 50. There is often some delay in realizing what has
happened, and the second wellbore 40 may further drift away from
the target box 50. As this drift is corrected, the second wellbore
40 may no longer retain a straight profile which may lead to
problems running casings, liners, etc. along the second wellbore
40.
[0052] It is possible to reduce the ambiguity by taking a single
reading from the source and subtracting the Earth's magnetic field
from that reading. However, in order to determine the components of
the Earth's magnetic field (as seen along the axis of the
magnetometers), three things/indicia/metrics may be useful,
including: the strength of the field; the dip of the field; and the
direction of the field with respect to the long axis of the probe.
The direction of the field, at times, can be problematic, but can
be assumed by fitting the ranging data (e.g., changing the azimuth
of the Earth magnetic field), to change the ranging data. This
fitting can be done by iteration to provide a close fit. However,
previous assumptions can easily affect this result, affecting the
absolute and relative positions of the wellbore being drilled, and
so multiple historical azimuths may be adjusted to produce a
resultant survey that can be used. Derivation of the azimuths using
magnetic survey data can be adversely affected by residual magnetic
particle inspection (MPI) magnetism in the first wellbore 10,
residual magnetism left in the core of the electromagnet 60,
magnetism induced in the casing from the electromagnet 60, and BHA
magnetism. These contributions to the residual magnetism can
deflect the magnetically derived azimuth and can give a misleading
Earth's magnetic field removal that could lead to incorrect
absolute and relative positions for the second wellbore 40.
[0053] These magnetic ranging techniques can also suffer from
increasing error with distance between the first wellbore 10 and
the second wellbore 40, since as the size of the signals decreases,
the noise-to-signal ratio increases. As a result, positional
uncertainty can be created, leading to incorrect steering of the
second wellbore 40.
[0054] Magnetic ranging techniques can also have difficulty in
determining the 180 degree, left right issue, as mentioned above.
If the Earth's magnetic field could be well understood, then it
could be simple to remove the Earth's magnetic field from a single
reading to derive the magnetic vector from the target. To derive
how the Earth's magnetic field affects each magnetometer, it can be
advantageous to have accurate knowledge of each of the following:
Earth's total magnetic field; the magnetic dip angle M.sub.Dip; and
azimuth. The Earth's total magnetic field and M.sub.Dip can be
derived from models like the British Geological Survey (BCS) Global
Geomagnetic Model (BGGM), High Definition Geomagnetic Model (HDGM)
of the National Geophysical Data Center of the National Oceanic and
Atmospheric Administration (NOAA), etc. These models, however, fail
to take into account all local anomalies, possibly resulting in
errors of about 900 nanoTesla in the total magnetic field and about
0.7 degrees in M.sub.Dip (at about 70 degrees latitude). Also, the
azimuth may be deflected by magnetism from the first wellbore and
the BHA. The total magnetic field and M.sub.Dip can be measured at
or near the location of the second wellbore 40, which generally
gives good results. The azimuth can be derived down hole as it is
the direction in which the survey tool is pointing with respect to
the field it senses. However, because the field is deflected, it
may not be a true azimuth and therefore the backed out interference
field would be in error. These effects may be a problem as
algorithms like multi-station analysis that may be used to correct
for BHA interference, generally assume the presence of a single
source of interference. When the second wellbore 40 (e.g., a
drilling well) leaves the build section to drill the lateral
section, it is subjected to interference from the BHA and the first
wellbore 10 (e.g., a target well). These two sources can make it
difficult to solve the interference effects and the derivation of
the azimuth, thereby introducing an error in the derivation of the
relative position of the second wellbore 40. This problem can be
solved when the azimuth is derived from high accuracy gyroscopic
measurements.
Gyro-Assisted Magnetic Ranging Systems and Methods
[0055] FIG. 5A is a flow diagram of an example method 100 to
determine a distance, a direction, or both between an existing
first wellbore 10 and at least one sensor module 20 of a drill
string 30 within a second wellbore 40 being drilled in accordance
with certain embodiments described herein. In an operational block
120, the method 100 comprises using the at least one sensor module
20 to measure a magnetic field and to generate at least one first
signal indicative of the measured magnetic field. In an operational
block 140, the method 100 further comprises using the at least one
sensor module 20 to gyroscopically measure an azimuth, an
inclination, or both of the at least one sensor module 20 and to
generate at least one second signal indicative of the measured
azimuth, inclination, or both. In an operational block 160, the
method 100 further comprises using the at least one first signal
and the at least one second signal to calculate a distance between
the existing first wellbore 10 and the at least one sensor module
20, a direction between the existing first wellbore 10 and the at
least one sensor module 20, or both a distance and a direction
between the existing first wellbore 10 and the at least one sensor
module 20. In certain embodiments, the method 100 further comprises
using the calculated distance, the calculated direction, or both to
control the drill string 30 (e.g., a rotary steerable drill
string). For example, at least one control signal can be generated
(e.g., automatically) in response to the calculated distance, the
calculated direction, or both, and the at least one control signal
can be transmitted to a steering mechanism of the drill string
30.
[0056] FIG. 5B is a flow diagram of an example method 200 for
controlling a drill string 30 spaced from an existing first
wellbore 10, the drill string 30 drilling a second wellbore 40, in
accordance with certain embodiments described herein. In an
operational block 210, the method 200 comprises receiving at least
one first signal indicative of a magnetic field measured by at
least a first sensor module 22 of the drill string 30. The first
sensor module 22 comprises at least one magnetometer. In an
operational block 220, the method 200 further comprises receiving
at least one second signal indicative of an azimuth, an
inclination, or both measured by at least a second sensor module 24
of the drill string 30. The second sensor module 24 comprises at
least one gyroscopic sensor. In an operational block 230, the
method 200 further comprises calculating a distance between the
existing first wellbore 10 and the first sensor module 22, a
direction between the existing first wellbore 10 and the first
sensor module 22, or both a distance and a direction between the
existing first wellbore 10 and the first sensor module 22. In an
operational block 240, the method 200 further comprises generating,
in response to at least one of the calculated distance and the
calculated direction, at least one control signal to be transmitted
to a steering mechanism of the drill string 30. The method 200 can
be performed by a computer system (e.g., a microprocessor) in
operational communication with the drill string 30 (e.g., with at
least the first sensor module 22, at least the second sensor module
24, and the steering mechanism of the drill string 30).
[0057] In certain embodiments, systems and methods can be used to
advantageously address the problems or limitations of magnetic
ranging systems and methods by using at least one sensor module
comprising at least one gyroscope ("gyro") to provide information
(e.g., information regarding the azimuth) to supplement information
provided by the magnetic ranging (e.g., information provided by at
least one sensor module comprising at least one magnetometer).
Certain such embodiments combine the use of at least one gyro with
at least one of the magnetic ranging systems and methods described
above to advantageously negate some of the problems described
above.
[0058] In certain embodiments, the gyro-assisted magnetic ranging
systems and methods described herein may allow accurate relative
and absolute spatial positions to be acquired from the ranging data
(e.g., providing definitive results while avoiding complex and
imprecise calculations based on noisy magnetic measurements alone
to remove Earth's field effects). In certain embodiments, comparing
the gyro-derived information regarding azimuth and inclination to
the magnetometer-derived information can be used to identify
erroneous contributions to the magnetometer measurements (e.g., due
to going out of calibration, magnetic contributions from ferrous
formations containing magnetite or basaltic layers or from
geothermal wells in volcanic formations). In addition, when using
an axial magnetometer to provide information about the approach of
an existing wellbore, comparing the gyro-derived information to the
magnetometer-derived information can be used to optimize the
magnetic ranging process by reducing (e.g., avoiding, minimizing)
the effects of axial magnetization from the drill string itself
along the tool axis, thereby allowing for ranging while
drilling.
[0059] In certain embodiments, the gyro-assisted magnetic ranging
systems and methods described herein may provide gyro-derived
information can be used to provide a definitive survey of the
wellbore 40 immediately after tripping the drill string 30 out of
the wellbore 40. In contrast, using magnetic ranging- or
MWD-derived information alone can take two to three days of
analysis to generate a full survey which includes both azimuth and
inclination. In certain embodiments, back calculations and
iterative techniques may be used to estimate the wellbore
position.
[0060] In certain embodiments, the gyro-assisted magnetic ranging
systems and methods described herein can be used to automate rotary
steerable drilling (e.g., by reducing the role of a human operator
in steering the drill string 30 while drilling the second wellbore
40 as compared to conventional magnetic ranging techniques). The at
least one sensor module 20 can comprise a MWD sensor pack of a
rotary steerable drilling tool. For example, the at least one
sensor module 20 can comprise at least one gyro module and at least
one magnetometer module, or a first sensor module 22 comprising at
least one gyro and a second sensor module 24 comprising at least
one magnetometer. The at least one sensor module 20 can be
positioned in a wide range of locations along the drill string 30
(e.g., below the steering mechanism, in the steering mechanism, or
above the steering mechanism) and can be used to provide the
measurements to be used as part of the gyro-assisted magnetic
ranging. For example, the at least one sensor module 20 can be
above the steering mechanism by a distance between 40 meters and 70
meters. For another example, the at least one sensor module 20
positioned below the steering mechanism in proximity to the drill
bit (e.g., directly behind the drill bit, above the drill bit by a
distance between 10 meters and 15 meters) in the rotary steerable
tool can be used as part of the gyro-assisted magnetic ranging. In
certain embodiments, using at least two magnetic sensor modules
(e.g., one sensor module positioned above the steering mechanism
and another sensor module positioned below the steering mechanism)
can provide information on the angle of approach of the drill
string 30 to the existing first wellbore 10 (see, e.g., U.S. Pat.
Nos. 8,095,317 and 8,185,312). In certain embodiments, using at
least two magnetic sensor modules can provide information to be
used to reduce the effect of bias created by magnetic interference
from BHA components. For example, measurements taken with a first
magnetic sensor module near a ferromagnetic BHA component (e.g.,
sufficiently near to provide measurements affected by a magnetic
field of the BHA component) and a second magnetic sensor module
spaced away from the ferromagnetic BHA component (e.g.,
sufficiently away to provide measurements not affected by a
magnetic field of the BHA component) can be subtracted from one
another to provide information regarding residual biases due to the
magnetic field of the BHA component.
[0061] Certain embodiments described herein are configured to drill
a predetermined well path while locating a target well with a
reduced role of a human operator (e.g., automatically). The
predetermined well path can be selected to keep a predetermined
distance between the target well and the well being drilled, to
intercept the target well at a predetermined position (e.g., true
vertical depth) or formation, or to find and stay within a
formation. In certain embodiments, the gyro-assisted magnetic
ranging systems and methods described herein can be used in
conjunction with active magnetic ranging to automate rotary
steerable drilling. In certain other embodiments, the gyro-assisted
magnetic ranging systems and methods described herein can be used
in conjunction with passive ranging (e.g., detection of remnant
magnetization in the target well casing, for target well
interception or target well avoidance) to automate rotary steerable
drilling.
[0062] In certain embodiments, the gyro-assisted magnetic ranging
systems and methods described herein can provide more accurate
detection or warnings of approaching a target well. For example,
while magnetic ranging alone may give a warning of the second
wellbore 40 approaching the first wellbore 10, the gyro
measurements can be used to generate values of the azimuth and
inclination of the second wellbore 40. These values can be compared
to those of previous surveys of the first wellbore 10 to determine
a proximity between the first wellbore 10 and the second wellbore
40. In addition, the gyro measurements can be used to estimate the
magnetic fields expected to be detected at the particular azimuth
and inclination determined by the gyro sensor module 24. Deviations
or distortions between the expected magnetic fields and the
measured magnetic fields can be indicative of the existence of the
first wellbore 10 in proximity to the second wellbore 40. For
example, deviations of the measured magnetic field magnitude and
dip angle (e.g., calculated using equations as disclosed more fully
below) and the expected values of these same quantities (e.g., from
the Earth's magnetic field) can be used to indicate the existence
of the first wellbore 10 in proximity to the second wellbore
40.
[0063] In certain embodiments, the gyro-assisted magnetic ranging
systems and methods described herein include a gyro (e.g., a gyro
having small errors at high angles of inclination), in conjunction
with magnetic survey instruments. Certain such embodiments may
overcome the problem of poorly derived azimuths and Earth's
magnetic field removal in conventional ranging systems. Certain
such embodiments can advantageously provide more accurate ranging
data for the relative position of the second wellbore 40. In
addition, the gyro data may give a more reliable and accurate
absolute wellbore position.
[0064] In certain embodiments, by using a gyro, the gyro-assisted
magnetic ranging systems and methods described herein may
advantageously reduce the number of ranging survey measurements to
be taken as compared to magnetic ranging systems and methods that
do not utilize gyro measurements. By sending inclination and
azimuth measurements to the surface to calculate steering commands,
the gyro-assisted magnetic ranging systems and methods described
herein may reduce the number of high resolution magnetometer
measurements (e.g., 100 nanotesla) transmitted to the surface for
the ranging calculations, as compared to conventional MWD-based
ranging systems and methods.
[0065] For example, the number of magnetic ranging survey
measurements taken can be reduced (e.g., to one per casing joint),
thereby saving time and allowing faster well completion. For
example, the duration of the magnetic ranging process at each
station (e.g., taking six high-resolution magnetometer and
accelerometer measurements at each station, with the stations
spaced from one another by about 11-13 meters) can be 8 minutes
(assuming mud pulse telemetry), resulting in a total ranging time
using magnetic ranging alone of 96 minutes for each 100 meters
drilled. By using gyro measurements in combination with magnetic
ranging measurements to provide information regarding azimuth and
inclination at intervening stations (e.g., two relatively
low-resolution measurements of 2 minutes duration each), the number
of magnetic survey measurements can be reduced (e.g., to one per
100 meters). Thus, the total time for which drilling is stopped for
the gyro-assisted magnetic ranging technique then can be about 24
minutes per 100 meters drilled, which is about one hour less for
every 100 meters drilled using magnetic ranging alone. Besides
saving time during drilling, by reducing the period of time during
which the drill string 30 is stopped for taking measurements (e.g.,
fewer long-duration magnetic ranging measurements being made),
certain such embodiments can reduce the probability of the drill
string 30 getting stuck in the wellbore 40. Note that the benefits
of time saved and reduced probability of getting stuck for
gyro-assisted magnetic ranging as compared to magnetic ranging
alone using electromagnetic ranging relate largely to the time
taken to transmit data to the surface, which would be less in
configurations in which faster communication is possible (e.g., the
time per magnetic ranging measurement is significantly smaller for
electromagnetic telemetry than for mud pulse telemetry).
[0066] To illustrate this aspect, FIG. 6A schematically illustrates
the positions of a number of standard magnetic ranging survey
measurements to be taken along a target box 50 that is 570 meters
long and FIG. 6B schematically illustrates the positions of a fewer
number of gyro-assisted ranging survey measurements to be taken
along the target box 50. As shown in FIG. 6A, because of the larger
reference errors in magnetic ranging, many magnetic ranging survey
measurements (at positions denoted by vertical arrows along the
target box 50) are to be taken along the target box 50 in an
attempt to keep the second wellbore 40 within the target box 50. In
contrast, as shown in FIG. 6B, using gyro-assisted magnetic
ranging, the number of survey measurements to be taken along the
target box 50 (at positions denoted by vertical arrows along the
target box 50) can be fewer (e.g., by approximately a factor of 16)
than in FIG. 6A. For example, if a gyro has a reference error of
0.3 degree, then it is possible the second wellbore 40 would leave
the target box 50 after 190 meters, assuming no ranging error. With
the inclusion of a gyro, the influence of the ranging error can be
reduced (e.g., by only performing gyro-assisted ranging survey
measurements when the uncertainty reaches the edge of the target
box 50). For example, allowing for a horizontal positional ranging
error of about +/-0.25 meter (at 5 meters), the second wellbore 40
could leave the target box 50 after 143 meters has been drilled. It
may be expedient to allow for other errors and so a 120 meter
ranging interval could be optimum, thereby saving time and being
less problematic than the standard ranging survey practice for
surveying every joint (about every 10-13 meters). Certain
embodiments described herein with the inclusion of a gyro could
reduce the ranging survey requirement by about 90%.
[0067] In addition, by providing azimuth and inclination
information, the gyro measurements can be used to allow the Earth's
magnetic field to be removed from the ranging calculations. For
example, once the azimuth and inclination of the downhole portion
are known from the gyro measurements, reference information (e.g.,
a model; a database) regarding the Earth's magnetic field at
various azimuths and inclinations can be accessed, and the measured
azimuth and inclination can be used to determine a contribution
from the Earth's magnetic field to the measured magnetic field that
can be expected at the measured azimuth and inclination. This
expected contribution to the measured magnetic field can then be
subtracted from the measured magnetic field to provide a corrected
measured magnetic field to be used in the ranging calculations, as
described more fully below.
[0068] Gyro-assisted magnetic ranging can be used to drill infill
wells that are positioned between existing well pairs, and to
re-drill wells positioned adjacent to the drilled second well.
Infill wells are when the lateral sections are often about 100
meters apart, and another well is drilled in between to aid
production or injection. Re-drills are often used when wells have
sanded up, steam jumped, or other causes. When either drilling
infill wells or re-drilling wells, it can be advantageous to have
access to an accurate absolute position of the existing wells. If
the absolute position is accurate, then the risk of collision can
be avoided (e.g., reduced) and the recovery from the reservoir can
be optimized. As previously described, magnetic surveys may be
adversely affected by interference from BHAs, other wells, magnetic
storms, etc. Such interference may create large uncertainties in
the absolute wellbore position. In certain embodiments described
herein, use of a gyro in ranging systems and methods does not
suffer from such issues and can provide increasingly accurate
absolute and relative wellbore positions. Also, the less frequent
use of the electromagnet means the casing in the first wellbore may
be less magnetized and therefore less likely to distort the
electromagnetic field.
Determining the Interference Field Due to Proximity to Another
Wellbore
[0069] In certain embodiments, gyro-assisted magnetic ranging uses
a determination of the interference field due to the proximity of
the wellbore being drilled to another previously-drilled wellbore.
At least one magnetometer module of the at least one sensor module
20 can be subject to the Earth's magnetic field plus an
interference field which, for the purpose of the following
analysis, can be assumed to be wholly the result of proximity of
the at least one magnetometer module to a nearby wellbore (e.g.,
the first wellbore 10; the target wellbore). For example, in
passive ranging, the remnant magnetization of at least one casing
or casing joint of the target wellbore can contribute to the
interference field. In another example, in active ranging, a
magnetic field created within the target wellbore (e.g., using an
electromagnet such as a solenoid) can contribute to the
interference field, in addition to any remnant magnetization.
[0070] The components of the magnetic field sensed by the at least
one magnetometer module (H.sub.xr, H.sub.yr, H.sub.zr) can be
expressed as the sum of the components of the Earth's magnetic
field (H.sub.x, H.sub.y, H.sub.z) and the components of the
interference field (H.sub.xi, H.sub.yi, H.sub.zi) as follows:
H.sub.xr=H.sub.x+H.sub.xi
H.sub.yr=H.sub.y+H.sub.yi
H.sub.zr=H.sub.z+H.sub.zi
The ranging calculations can be based upon estimates of the
interference field, the components of which can be determined by
subtracting the components of the Earth's magnetic field from the
components of the magnetic field measured by the at least one
magnetometer module:
H.sub.xi=H.sub.xr-H.sub.x
H.sub.yi=H.sub.yr-H.sub.y
H.sub.zi=H.sub.zr-H.sub.z
[0071] In certain embodiments, the components of the Earth's
magnetic field to be subtracted from the components of the measured
magnetic field can be derived using knowledge of the total Earth's
magnetic field (H.sub.e), the magnetic dip (D), and the orientation
of the drilling tool as defined by its azimuth (A), inclination
(I), and high side rotation (R), viz.:
H.sub.x=H.sub.e(cos D cos A cos I sin R-sin D sin I sin R+cos D sin
A cos R)
H.sub.y=H.sub.e(cos D cos A cos I cos R-sin D sin I cos R-cos D sin
A sin R)
H.sub.z=H.sub.e(cos D cos A sin I+sin D cos I)
[0072] Values of the inclination and high side rotation can be
obtained from accelerometer measurements by the at least one sensor
module 20 (e.g., by one or more accelerometers), values of the
azimuth can be obtained from gyroscopic measurements by the at
least one sensor module 20 (e.g., by one or more gyros), and values
of the total Earth's magnetic field and the magnetic dip can be
known.
[0073] Note that the azimuth of the drilling tool is used to define
the Earth's magnetic field effect on the magnetometers. If the
azimuth is not well known (e.g., guessed), then the results of
H.sub.x, H.sub.y, and H.sub.z will be in error. Any results that
follow that are used to determine ranging data (e.g., distance and
direction to the target well), such as the total interference field
(H.sub.i), the magnetic inclination (M.sub.i), and the direction of
the interference vector (D.sub.v), will also be in error. If the
azimuth is well known (e.g., from an accurate gyro measurement),
then the resulting ranging data should also be accurate.
Furthermore, if any of these values are not well defined, then the
computed components of the Earth's magnetic field (H.sub.x,
H.sub.y, H.sub.z) will be in error, and it follows that any ranging
calculations carried out based on the estimated interference field
will also be in error.
[0074] For ranging, the following values can be calculated using
the components of the estimated interference field (H.sub.xi,
H.sub.yi, H.sub.zi). The total interference field (H.sub.i) can be
expressed as:
H.sub.i=(H.sub.xi.sup.2+H.sub.yi.sup.2+H.sub.zi.sup.2).sup.1/2. The
magnetic inclination (M.sub.i) with respect to the longitudinal
axis of the tool can be expresses as the angle: M.sub.i=A Tan
[(H.sub.xi.sup.2+H.sub.yi.sup.2).sup.1/2/H.sub.zi]. The direction
of the interference vector (D.sub.v) with respect to the projection
of the longitudinal axis of the tool into the horizontal plane can
be expressed as:
D.sub.v=A Tan
[((G.sub.x.sup.2+G.sub.y.sup.2+G.sub.z.sup.2).sup.1/2*(H.sub.xi*G.sub.y-H-
.sub.yi*G.sub.x))/(H.sub.zi(G.sub.x.sup.2+G.sub.y.sup.2)+H.sub.xi*G.sub.x*-
G.sub.z+H.sub.yi*G.sub.y*G.sub.z)]
where Gx, Gy, and Gz are the three orthogonal components of the
gravitational vector pointing towards the Earth's center.
[0075] Other effects on the reliability of the interference vector
include, but are not limited to, BHA magnetic interference,
adjacent wells, magnetic storms, formation effects (e.g., high Fe
content, etc.) and noise in the electromagnet system. Some of these
effects can be negated (see, e.g., "Location Determination Using
Vector Measurements," G. McElhinney, EP Pat. No. 0682269, 12 May
1995; "Electromagnetic Array for Subterranean Magnetic Ranging
Operations," G. McElhinney, R. Moore. US Pat. Appl. Publ. No.
2012/0139530, 7 Jun. 2012. An estimation of these effects, after
corrections have been applied, may be a ranging distance error of
the order of 10 to 50 centimeters at 5 meters displacement.
[0076] It can be advantageous to correct as many detrimental
effects as possible to increase the accuracy of the ranging data.
For example, using methods such as Earth's field monitoring at or
near the rig site, multi-station analysis to remove BHA
interference, and measuring the BHA interference, pre-run, can be
used to supplement the gyro-assisted magnetic ranging systems and
methods described herein. Alternative methods, including but not
limited to interpolated in-field referencing (IIFR) which takes
into account diurnal variations in the magnetic field and uses
interpolation between measurements from reference stations located
some distance apart to determine field variations at the drill
site, may also be employed.
[0077] For BHA interference measurements, an analysis of the
electromagnetic vectors can indicate the presence of BHA
interference and can be used to help remove its detrimental effect.
For example, FIG. 7 schematically illustrates a comparison between
balanced electromagnetic vectors and unbalanced electromagnetic
vectors due to BHA interference (note that FIG. 7 omits the
contribution from the Earth's field for clarity). In certain
embodiments, the BHA interference contribution can be considered to
be a constant, and it can be subtracted from the measured magnetic
field to derive the magnetic field due to the electromagnet 60 and
the Earth's field. If there is a BHA interference vector present,
then an imbalance in the +/-electromagnetic vector will be
measured, as shown in FIG. 7. This imbalance can be solved for by
removing the BHA interference vector (e.g., to create a
balanced+/-electromagnetic vector once the contribution from the
Earth's field has been removed). Various mathematical processes
(see, e.g., "Method for Correcting Directional Surveys," G.
McElhinney, EP Pat. No. 0793000, May 14, 1996) may be employed to
remove the BHA interference vector. Once the magnetic fields (e.g.,
electromagnetic vectors) due solely to the electromagnet 60 are
determined at a position of the at least one sensor 20, these
values can be used as described herein to determine the position of
the at least one sensor module 20 within the second wellbore 40
relative to the electromagnet 60 in the first wellbore 10. This
determined position can then be used to steer the drill string 30
in the second wellbore 40 to a predetermined position relative to
the first wellbore 10.
Rotary Steerable Drilling in Conjunction with Gyro-Assisted
Magnetic Ranging Surveys
[0078] While the discussion below addresses the drilling of a
second wellbore 40 alongside (e.g., parallel) to an existing first
wellbore 10, the systems and methods described are equally
applicable for the drilling of a second wellbore 40 configured to
intercept a first wellbore 10 (e.g., in the event of a blowout).
Similar guidance strategies may be adopted for the automation of
such a process. For example, gyro-assisted magnetic ranging can be
used for the terminal stages of the interception process to reduce
the role of a human operator in steering the second wellbore to
intersect the first wellbore.
[0079] In certain embodiments, a drilling tool 30 (e.g., a drill
string) is controlled (e.g., steered) in response to signals
derived from gyro-assisted magnetic ranging survey measurements to
follow a desired path (e.g., trajectory). For example, the drilling
tool 30 can be steered to drill a second wellbore 40 that follows a
course alongside and parallel to an existing first wellbore 10. The
desired path of the second wellbore 40 can be controlled to remain
within at least one target box 50 that follows the existing first
wellbore path at a pre-defined distance (e.g., a fixed distance
above, a fixed distance below, a fixed distance left, a fixed
distance right) from the first wellbore path. Steering signals
(e.g., commands) can be generated to cause the drilling tool 30 to
form the second wellbore 40 to follow, and to attempt to intercept,
a sequence of target boxes 50 defined at intervals along the first
wellbore path. In certain such embodiments (e.g., where bending is
applied to a flexible shaft of the rotary steerable tool in
proportion to the angle between the tool axis and the target line
of sight), the steering signal magnitudes are proportional to the
angular differences (e.g., in inclination and azimuth) between the
next target line of sight and the orientation of the drilling tool
30. Given knowledge of the coordinates of the drilling tool 30 and
the location of the first wellbore 10 in the chosen reference
frame, the target line of sight relative to the drilling tool 30
can be updated for each well section.
[0080] In certain embodiments, the second wellbore path may be a
predetermined distance (e.g., 3-5 meters separation) from the first
wellbore path that is sufficiently small such that magnetic ranging
is conducted. In certain such embodiments (e.g., when a new well is
to be drilled in close proximity to an existing well, such as in
the case of SAGD applications), magnetic ranging is viable and
gyro-assisted magnetic ranging can be used to provide information
used to achieve the desired second wellbore path (e.g.,
trajectory). For example, standard survey methods may be used to
guide the second wellbore 40 to within range of the first wellbore
10 such that magnetic ranging can be used. Thereafter, a guidance
strategy based on a local reference frame defined by the relative
separation and orientation of the second wellbore 40 with respect
to the first wellbore 10 may be adopted. In certain such
embodiments, the drilling tool location with respect to the next
target boxes can be updated periodically as new ranging
measurements becomes available.
[0081] In certain embodiments, a closed-loop drilling process is
used to control (e.g., steer) a drilling tool 30 (e.g., a rotary
steerable drill string). For example, a BHA within the second
wellbore 40 can comprise a drill bit at an end of the rotary
steerable drill string, a first sensor module 22, and a second
sensor module 24 spaced from the first sensor module 22 along the
rotary steerable drill string in a direction away from the drill
bit. The first sensor module 22 can comprise a plurality of rotary
steerable sensors (e.g., a plurality of magnetometers,
accelerometers, and/or gyros). The second sensor module 24 can
comprise a magnetic MWD sensor pack and a gyroscopic GWD sensor
pack.
[0082] FIG. 8A schematically illustrates an example configuration
of a drilling tool 30 configured to drill a second wellbore 40
(e.g., drilling well) along a desired path parallel to and in close
proximity to a first wellbore 10 (e.g., target well). The drilling
tool 30 comprises a steering mechanism configured to controllably
adjust the tool path direction (e.g., direction in which the second
wellbore 40 is being drilled) in response to at least one steering
signal (e.g., command) from a computer system (e.g., a computer
processor mounted on the drilling tool 30 or outside the second
wellbore 40). The drilling tool 30 further comprises at least a
first sensor pack 22 positioned below the steering mechanism (e.g.,
in proximity to a drill bit of the drilling tool) and at least a
second sensor pack 24 positioned above the steering mechanism
(e.g., such that the steering mechanism is between the first sensor
pack 22 and the second sensor pack 24).
[0083] FIG. 8B is a flow diagram of an example method 400 of
drilling a second wellbore 40 (e.g., drilling well) along a desired
path parallel to a first wellbore 10 (e.g., target well). The
second wellbore 40 can be in close proximity to the first wellbore
10 (e.g., within 3-5 meters). The method 400 can be performed by
the computer system of the drilling tool 30. In an operational
block 410, a target position can be defined along a desired path of
the second wellbore 40. The target position can be spaced a
distance (d) from the current position of the drilling tool 30. In
an operational block 420, magnetic ranging measurements relative to
the first wellbore 10 and gyroscopic measurements of an azimuth, an
inclination, or both of the drilling tool 30 are made, and these
measurements are used to determine a distance ({tilde over (s)})
between the current position of the drilling tool 30 and the first
wellbore 10. For example, the distance ({tilde over (s)}) can be
measured or derived using magnetic ranging measurements using the
first sensor module 22, the second sensor module 24, or both the
first sensor module 22 and the second sensor module 24 with these
magnetic ranging measurements corrected using the gyroscopic
measurements as described herein. Magnetic ranging measurements can
be used to provide information regarding the distance of the
drilling tool 30 (e.g., an end portion of the drill string, the
drill bit, the first sensor module 22) from the first wellbore 10
and the direction of the second wellbore path with respect to the
first wellbore path.
[0084] In an operational block 430, a distance (.DELTA.s={tilde
over (s)}-s) between the first wellbore path and the desired path
of the second wellbore 40 can be calculated. In an operational
block 440, a target sightline angle
( .beta. = arctan [ .DELTA. s d ] ) ##EQU00001##
with respect to the desired path of the second wellbore 40 can be
calculated. In an operational block 450, a tool path direction (a)
with respect to the first wellbore path can be measured (e.g.,
using the first sensor module 22, the second sensor module 24, or
both the first sensor module 22 and the second sensor module 24).
In an operational block 460, a steering angle
(.gamma.=.alpha.-.beta.) can be calculated. In an operational block
470, a steering signal (e.g., command) can be transmitted to the
steering mechanism (e.g., a shaft bending mechanism, an example of
which is described in U.S. Pat. No. 8,579,044, which is
incorporated in its entirety by reference herein) to control the
steering mechanism to adjust the tool path direction by the
steering angle. In certain embodiments, the steering signal has a
magnitude proportional to the steering angle. In an operational
block 480, a new target position along the desired path of the
second wellbore 40 is defined, the new target position a distance
(d) from the current position of the drilling tool 30 (e.g., since
the drill string has moved by virtue of drilling the second
wellbore 40). The method 400 can further comprise iterating the
operational blocks 420-480 (denoted in FIG. 8B by the arrow
490).
[0085] FIG. 9 schematically illustrates an example measurement of
the tool path direction (a) with respect to the first wellbore path
using the first sensor module 22 and the second sensor module 24.
Using information regarding the distance (h) between the first
sensor module 22 and the second sensor module 24, the measured
distance ({tilde over (s)}.sub.1) between the current position of
the first sensor module 22 and the first wellbore 10, and the
measured distance ({tilde over (s)}.sub.2) between the current
position of the second sensor module 24 and the first wellbore 10,
the tool path direction can be provided by the relation:
.alpha. = arcsin ( s ~ 2 - s ~ 1 h ) . ##EQU00002##
A similar calculation can be performed for a "dogleg" section of
the drilling tool 30, given an estimate of the bend of the drilling
tool 30 between the first sensor module 22 and the second sensor
module 24.
[0086] FIG. 10 schematically illustrates an example progression of
the drilling tool 30 using multiple iterations of the example
method 400 of FIG. 8B. With each successive target point along the
desired path of the second wellbore 40, the achieved path of the
second wellbore 40 gets closer to the desired path.
[0087] In certain embodiments, the second wellbore path may be a
predetermined distance (e.g., 30-50 meters separation) from the
first wellbore path that is sufficiently large such that magnetic
ranging is not conducted. In certain such embodiments (e.g., when
so-called in-fill drilling is carried out), the steering signals
can be based on information regarding the absolute spatial position
of the first wellbore 10 and the second wellbore 40. The first
wellbore path may be provided by surveys conducted earlier while
the second wellbore path may be determined using an on-board survey
system (e.g., a magnetic survey system, a gyro survey system, or a
combination of a magnetic and a gyro survey system) of the drilling
tool 30 within the second wellbore 40. For example, a gyro survey
system can be used to provide information regarding the second
wellbore path, and information from magnetic sensors can be used to
supplement the gyro-derived information (e.g., for quality
assurance of changes in the gyro-derived information). In certain
embodiments, the distance between the second wellbore 40 and the
first wellbore path is too large for magnetic ranging to be used,
while in certain other embodiments, magnetic ranging measurements
are used to supplement the absolute spatial position
measurements.
[0088] For example, the inclination of the drilling tool 30 may be
determined using measurements of the gravitational vector obtained
from a plurality (e.g., a triad) of accelerometers of the drilling
tool 30, the accelerometers mounted to have their sensitive axes
nominally coincident with the xyz axes of the drilling tool 30. The
tool azimuth may be determined using a combination of the
gravitational measurements and measurements of the Earth's rotation
vector obtained from a plurality (e.g., a triad) of rate
gyroscopes, also mounted with their sensitive axes nominally
coincident with the xyz axes of the drilling tool 30. Steering
signals (e.g., commands) can then be generated (e.g., by the
computer system) and transmitted to the steering mechanism, with
the steering signals being functions of the inclination and azimuth
differences between the target direction and tool orientation so as
to cause the drilling tool 30 to rotate to point in the direction
of the next target location as drilling proceeds.
[0089] To define accurately the target vector in the chosen
reference frame, accurate information regarding the drilling tool
position is desirable. Such accurate drilling tool position
information can be generated by combining the measured inclination
and azimuth with the distance moved along the path of the second
wellbore 40 (e.g., the measured depth of the second wellbore 40).
For example, such information can be generated using a minimum
curvature process. Other methods for determining the depth of the
second wellbore 40 can be based entirely on downhole measurements
(rather than surface measurements), examples of which are described
in U.S. Pat. Nos. 6,957,580 and 8,065,085, each of which is
incorporated in its entirety by reference herein.
[0090] In general, the path of the first wellbore 10 will not be
straight. Therefore, the absolute location of the target box 50
will move as the second wellbore 40 is drilled in order to maintain
a fixed relative position with respect to the first wellbore 10. A
strategy is therefore desirable for moving from one target box
location to the next as the second wellbore 40 is drilled. One
possible strategy is to select a new target box 50 as the second
wellbore 40 approaches the previous target box 50. The frequency of
the target boxes along the desired wellbore path, along with the
dog-leg capability of the rotary steerable tool, can be selected to
ensure that the distance of the second wellbore 40 from the first
wellbore 10 is maintained to within acceptable limits.
Examples of Gyro-Assisted Magnetic Ranging
[0091] In certain embodiments, the techniques described herein can
utilize combinations of static gyro surveying, static magnetic
surveying, magnetic ranging surveying, and dynamic magnetic
analysis during drilling at various phases of the drilling process.
In the example case of steam assisted gravity drainage (SAGD)
drilling, the ends 12, 42 at or near the Earth's surface of the
first wellbore 10 (e.g., the previously-drilled target wellbore)
and the second wellbore 40 (e.g., the wellbore being drilled),
respectively, are spaced substantially apart from one another, as
schematically illustrated in FIG. 11. FIG. 11 includes a plan view
of the first and second wellbores 10, 40 from above the Earth's
surface in a direction perpendicular to the Earth's surface, and a
section view in a direction parallel to the Earth's surface. In
certain such configurations, there is little or no magnetic
interference from the casings of the first wellbore 10 to be
detected by the at least one sensor module 20 of the drilling tool
30 in the second wellbore 40 being drilled. In certain such
configurations, standard gyro surveying can be performed during the
initial phase of the drilling process to determine the position of
the second wellbore 40, while monitoring data generated by the at
least one sensor module 20 (e.g., by at least one longitudinal axis
magnetometer) to detect the approach to the first wellbore 10
(e.g., the approach to the casings of the first wellbore 10 and/or
the electromagnet 60 within the first wellbore 10).
[0092] In certain embodiments, the electromagnet 60 can be
positioned at or near the planned interception point 70 of the two
wellbores (e.g., at the point at which the second wellbore 40 is
first at the desired distance for "twinning" the first wellbore
10). In certain embodiments, the electromagnet 60 can be switched
on (e.g., for a single shot of about 40 seconds) and positioned at
a distance (e.g., between about 10 meters and about 60 meters;
about 40 meters) before the interception point 70 and the
measurements by the axial magnetometer of the at least one sensor
module 20 can be monitored for the switch point, as described
below. Due to the possibility of any accumulative or gross errors
having been part of each well survey, the spatial positions may be
incorrect. To compensate for the possibility of any such spatial
positional errors, it can be advantageous to start the magnetic
ranging process sufficiently ahead of the perceived interception
point 70. In certain embodiments, the electromagnet 60 is
positioned at a distance before the interception point 70 that
advantageously allows safe drilling of the second wellbore 40 to
within a predetermined distance from the first wellbore 10 at which
magnetic ranging can be initiated and then used (e.g., to follow a
second wellbore path that is parallel to the first wellbore
path).
[0093] As the second wellbore 40 approaches the electromagnet 60 in
the first wellbore 10, the measured magnetic field 62 from the
electromagnet 60 will increase and the flux angle will change. The
measurements of the magnetic field can be used to derive (e.g.,
converted into) information regarding the position of the at least
one sensor module 20 relative to the electromagnet 60. In certain
embodiments, this derivation uses a predetermined mapping of the
parameters of the magnetic field generated by the electromagnet 60
(e.g., the three orthogonal components of the magnetic field; the
axial field component and the cross axial field component; the
magnitude and the flux angle) as a function of position relative to
the electromagnet 60. This mapping can be stored in memory of the
computer system controlling the drilling of the second wellbore 40
(e.g., can be stored in the form of a model, simulation, database,
lookup table, or other format). For example, a finite element
calculation package (e.g., David Meeker, "Finite Element Method
Magnetics," Version 4.2, User's Manual, found at
http://www.femm.info/Archives/doc/manual42.pdf, 2010) can be used
to derive the mapping of expected magnetic parameter values for
two-dimensional planar or axisymmetric configurations. The mapping
can have sufficient resolution to provide the desired level of
precision in position as a function of measured magnetic field 62.
In certain embodiments, interpolation among the values in the
mapping can be used to find the appropriate position corresponding
to the measured magnetic field parameter values.
[0094] In certain embodiments, as described more fully below, the
measured axial field component (M.sub.z) of the magnetic field
along the longitudinal axis of the second wellbore 40 may
advantageously be compared to the predetermined mapping of the
magnetic field so as to be used to determine the position of the at
least one sensor module 20 relative to the electromagnet 60. The
measured axial field component can be measured in this manner
during drilling of the second wellbore 40 (e.g., while the at least
one sensor module 20 is rotating about the longitudinal axis) or
during periods when drilling using the drill string 30 has stopped
(e.g., while the at least one sensor module 20 is not rotating
about the longitudinal axis). Use of the measured axial field
component is possible during drilling since the values of the axial
field component measured by the rotating sensor module 20 remain
unchanged during the drilling-related rotation of the at least one
sensor module 20 about its longitudinal axis. In other words, the
measured axial field component is not dependent on the rotation of
the at least one sensor module 20 about its longitudinal axis. In
addition, while the measured cross axial field components (M.sub.x
and M.sub.y) do vary while the at least one sensor module 20
rotates about its longitudinal axis, the measured flux angle
relative to the longitudinal axis of the at least one sensor module
20 (e.g., a tan [(M.sub.x.sup.2+M.sub.y.sup.2).sup.1/2/M.sub.z])
does not; it is dependent on the spatial position of the at least
one sensor module 20 relative to the electromagnet 60.
[0095] In certain embodiments, during periods in which drilling
using the drill string 30 has stopped, the measured cross axial
field components (M.sub.x and M.sub.y) may be used in addition to
the measured axial field component (M.sub.z), as described more
fully below. In certain such embodiments, the measured flux angle
relative to the longitudinal axis of the at least one sensor module
20 can be calculated from the axial and cross axial field
components (e.g., a tan
[(M.sub.x.sup.2+M.sub.y.sup.2).sup.1/2/M.sub.z]) without using
accelerometer measurements (e.g., from the at least one sensor
module 20). In certain other embodiments, such accelerometer
measurements may be used in conjunction with the measured axial and
cross axial field components (e.g., to determine the orientation
relative to the Earth's gravity). In certain embodiments, the
spatial position of the at least one sensor module 20 in the second
wellbore 40 relative to the electromagnet 60 in the first wellbore
10 can be determined by deriving the flux angle using the
orientation of the at least one sensor module 20 (e.g., using
accelerometer data), the angle of interception of the longitudinal
axis of the at least one sensor module 20, the cross axial tool
face interception (e.g., using accelerometer data), and the
orientation of the electromagnet 60 (e.g., from historical data).
Other methods may also be used to derive the target well flux angle
interception. In certain embodiments, the relative position of the
second wellbore 40 to the first wellbore 10 can be derived (e.g.,
while steering the drilling tool 30 with a rotary steerable
assembly or a three-dimensional steerable device).
[0096] FIG. 12A schematically illustrate the magnetic field 62
generated by an electromagnet 60 in accordance with certain
embodiments described herein. The left side of FIG. 12A
schematically illustrates a side view of the first wellbore 10, the
electromagnet 60, and the magnetic field 62, showing that the
magnetic field 62 is cross axial to the first wellbore 10 (e.g.,
with an axial field component parallel to the longitudinal axis of
zero) at various positions spaced from the first wellbore 10 and
along the first wellbore 10 (e.g., as denoted by the dashed lines).
As described more fully below, these positions can be considered to
be "switch points." The right side of FIG. 12A schematically
illustrates a view of the first wellbore 10, the electromagnet 60,
and the magnetic field 62, which also shows that the cross axial
component of the magnetic field 62 at these switch points are
directed either towards or away from the first wellbore 10. While
an increase or decrease of the current running through the
electromagnet 60 results in a respective increase or decrease of
the magnetic field intensity, the flux line shape of the magnetic
field remains unchanged by such changes of the current. Therefore,
a set of predetermined values of the parameters that characterize
the magnetic field generated by the electromagnet can be obtained
(e.g., by measuring these values for at least one current running
through the electromagnet 60 prior to the electromagnet 60 being
inserted into the first wellbore 10). The set of predetermined
values of the parameters that characterize the magnetic field can
then be used in comparison with values measured while the
electromagnet 60 is within the first wellbore 10 (once the
predetermined values are scaled to the same current running through
the electromagnet 60 during the measurements using the at least one
sensor module 20 in the second wellbore 40) in accordance with
certain embodiments described herein.
[0097] The top portion of FIG. 12B schematically illustrates an
SAGD configuration in which a portion of the second wellbore 40
(e.g., the drilling well) is in proximity to and parallel to a
portion of the first wellbore 10 (e.g., the target well) containing
the electromagnet 60. The bottom portion of FIG. 12B schematically
illustrates measured values of the axial field component (in
arbitrary units) measured by a longitudinal axis magnetometer at
various positions along the second wellbore 40. As the longitudinal
axis magnetometer of the at least one sensor module 20 moves along
the second wellbore 40, approaching the electromagnet 60 in the
first wellbore 10, and traversing past the electromagnet 60 (e.g.,
moving from left to right in FIG. 12B), the flux angle detected by
the longitudinal axis magnetometer will switch direction and the
axial field component detected by the longitudinal axis
magnetometer will vary. A first switch point (denoted in FIG. 12B
by a first star) can be defined as the position of the longitudinal
axis magnetometer where the component of the magnetic flux parallel
to the second wellbore 40 (e.g., the axial field component)
switches from pointing in one direction to pointing in the opposite
direction (e.g., changes sign from having a negative value to
having a positive value). A second switch point (denoted in FIG.
12B by a second star) can be defined as the position of the
longitudinal axis magnetometer where the component of the magnetic
flux parallel to the second wellbore 40 (e.g., the axial field
component) switches back to pointing in the direction it pointed
prior to reaching the first switch point (e.g., switches sign from
having a positive value to having a negative value). At each switch
point, the intensity of the detected magnetic field 62 can be used
to derive the total distance and cross axial distance to the pole
of the electromagnet 60. For example, by comparing the measured
magnetic field parameters to a set of predetermined values of these
parameters that characterize the magnetic field generated by the
electromagnet 60 (e.g., in a table, database, model, simulation, or
other form), certain embodiments described herein can derive (e.g.,
convert; translate) the measurements of the magnetic field to
values of the total distance and cross axial distance from the at
least one sensor module 20 to the pole of the electromagnet 60.
[0098] At the first switch point, a magnetic ranging survey can be
taken to determine the relative position of the second wellbore 40
with respect to the first wellbore 10. In certain embodiments, a
second magnetic ranging survey may be taken at the second switch
point if deemed necessary. For example, if the first magnetic
ranging survey is deemed to have a sufficiently reduced quality
(e.g., noisy; large jumps in values between adjacent points), then
the second magnetic ranging survey may be taken. One or both of the
switch points can be optimal positions at which to take a magnetic
ranging survey as the cross axial component of the magnetic flux is
large at the switch points, which can help define more accurately
the relative position of the second wellbore 40 to the first
wellbore 10.
[0099] Upon determining the relative position of the second
wellbore 40 to the first wellbore 10, action can be taken to steer
the second wellbore 40 within the target box 50. Once the relative
position of the second wellbore 40 is determined with respect to
the target box 50, the electromagnet 60 can be moved to a new
position further down the first wellbore 10 (e.g., 96 meters
further down the first wellbore 10) and gyro survey measurements
can be resumed at each survey station (e.g., at positions spaced
from one another by 11-13 meters). As the second wellbore 40 again
approaches the electromagnet 60, the above-described procedure can
be repeated.
[0100] The magnetic field 62 from the first wellbore 10 (e.g., the
electromagnet 60) should be detectable many tens of meters before
the second wellbore 40 is parallel to the first wellbore 10.
Although optimal positions for the magnetic ranging survey has been
described above at the first and second switch points, it is not
essential that a magnetic ranging survey is taken at one or both of
these positions. In certain embodiments, a magnetic ranging survey
can be carried out at any position along the second wellbore 40
where the magnetic field 62 from the first wellbore 10 is
detectable.
[0101] In certain embodiments, the procedure described herein can
be used for horizontal to vertical interceptions, or for high angle
interceptions (e.g., for Coal Bed Methane drilling, synthetic gas
drilling, and many other applications). For example, as
schematically illustrated by the top left portion and the right
portion of FIG. 12C, a second wellbore 40 can extend in a direction
that is not generally parallel to the first wellbore 10 (e.g., that
crosses above or below the first wellbore 10). As shown in the
bottom left portion of FIG. 12C, as the longitudinal axis
magnetometer of the at least one sensor module 20 moves along the
second wellbore 40, approaching the electromagnet 60 in the first
wellbore 10, and traversing past the electromagnet 60 (e.g., moving
from left to right in the top left portion of FIG. 12C), the
measured axial field component (shown in arbitrary units in the
bottom left portion of FIG. 12C) detected by the longitudinal axis
magnetometer will switch direction at the point of closest approach
of the second wellbore 40 to the first wellbore 10 (e.g., the
switch pattern in the high angle interceptions occurs at the point
of closest approach of the second wellbore 40 to the first wellbore
10).
[0102] In certain embodiments, the rate of change of the intensity
of the magnetic field, the flux angle, and the flux direction may
be used to determine the distances between the second wellbore 40
and the first wellbore 10 and the relative cross axial position.
For example, as the pole of the electromagnet 60 is approached, the
detected rate of change increases, and this information can be used
to dynamically monitor the approach of the drilling tool 30 to the
first wellbore 10.
[0103] FIG. 13A schematically illustrates an example configuration
including a table of example measured values of the various
parameters of the magnetic field 62 from the electromagnet 60 in
accordance with certain embodiments described herein. These
measured values can be determined by the at least one sensor module
20 (e.g., a longitudinal axis magnetometer) within the second
wellbore 40, and can be used in conjunction with a set of
predetermined correlation of these parameters (e.g., magnetic field
intensities; magnetic field components; flux angle; gradients of
these parameters) with the distance between the at least one sensor
module 20 and the electromagnet 60 to derive the position of the at
least one sensor module 20 to the electromagnet 60. Besides the
magnetic flux lines of the magnetic field 62, FIG. 13A includes
dashed lines which denote lines of constant total magnetic
intensity. The values shown in FIG. 13A are representative of
values after contributions from the Earth's magnetic field have
been removed.
[0104] For example, a longitudinal axis magnetometer within the
second wellbore 40 at a first position relative to the
electromagnet 60 in the first wellbore 10 can measure the values of
(measured total magnetic field intensity; the axial magnetic field
component; flux angle) to be (300 nT; -260 nT; 300 degrees). Using
the set of predetermined correlations of these parameters with
position, these measurements can be used to derive a relative
distance of 5.5 meters between the long axis magnetometer and the
electromagnet 60. Depending on the trajectory taken by the second
wellbore 40, a second set of measurements taken by the long axis
magnetometer at a second position can have different values of the
measured parameters. For example, a second set of measurements
taken by the long axis magnetometer at a second position can
measure the values to be (300 nT; +254 nT; 58 degrees). Again using
the predetermined correlation of these parameters with position,
the second position can be determined to be at the location labeled
"1" in FIG. 13A which is a relative distance of 6.7 meters from the
electromagnet 60. If instead the second position is at either the
location labeled "2" or "3" in FIG. 13A, the measured values will
be different and so will the relative distance to the electromagnet
60.
[0105] The gradients of one or more of the parameters of the
magnetic field can be used to determine the relative distance
between the at least one sensor module 20 and the electromagnet. In
certain embodiments, the relative distance at the second position
(e.g., at one of the locations labeled "1", "2", or "3" as shown in
FIG. 13A) can be determined using only the gradient of the axial
magnetic field component from the first position to the second
position. In certain other embodiments, the gradient of the flux
angle may also be used.
[0106] In certain embodiments, these gradients are determined using
measurements taken while drilling (e.g., when the at least one
sensor module 20 is rotating) or while the drill string 30 is
stationary (e.g., the at least one sensor module 20 is not
rotating). As described above, if the at least one sensor module 20
is rotating, the long axis magnetometer can still provide useful
measurements (e.g., to determine the gradient), while the
variations (e.g., noise) of measurements from the cross axial
magnetometers may not. The gradient values are dependent on the
angle of orientation and the relative spatial position between the
at least one sensor module 20 and the electromagnet 60. The
derivation of the relative distance during drilling can be useful
in determining whether the second wellbore 40 is approaching the
first wellbore 10, paralleling the first wellbore 10, or deviating
away from the first wellbore 10.
[0107] However, while the relative distance may be derived from the
magnetic field measurements, because the magnetic field is radially
symmetric around the electromagnet 60, additional information may
be used to make a determination of the angular position of the at
least one sensor module 20 with respect to the electromagnet 60.
For example, the orientation (e.g., inclination and azimuth) of
both the at least one sensor module 20 and the electromagnet 60 can
be known from static and historical surveys, and using such
information, the spatial position of the second wellbore 40
relative to the first wellbore 10 can be derived. In certain
embodiments, measurements taken while the at least one sensor
module 20 is not rotating (e.g., stationary) can be used to
determine which cross axial quadrant the at least one sensor module
20 is in with respect to the electromagnet 60. Once this additional
information is obtained, the second wellbore 40 can then be steered
correctly during drilling to its optimum position using only the
axial magnetic field component measurements, thereby providing the
ability to dynamically monitor the approach of the second wellbore
40 to the first wellbore 10.
[0108] FIG. 13B schematically illustrates an example well
paralleling configuration including a table of example measured
values of the various parameters of the magnetic field 62 from the
electromagnet 60 in accordance with certain embodiments described
herein. Besides the magnetic flux lines of the magnetic field 62,
the bottom right portion of FIG. 13B is a section view that
includes dashed lines which denote lines of constant total magnetic
intensity. The bottom left portion of FIG. 13B shows a
cross-sectional view of the cross-axial magnetic flux pattern in a
plane generally perpendicular to the first wellbore 10 and to the
second wellbore 40 (denoted by a star). The values shown in FIG.
13B are representative of values after contributions from the
Earth's magnetic field have been removed.
[0109] For example, at a series of positions labeled "A" through
"F" in FIG. 13B, a longitudinal axis magnetometer within the second
wellbore 40 can measure the various magnetic field values. The
values of the axial magnetic field component in the table of FIG.
13B can be measured dynamically (e.g., during drilling) while the
values of the total magnetic field intensity, flux angle, and cross
axial magnetic field components can be measured statically (e.g.,
while the drill string 30 is stationary). Using the set of
predetermined correlations of these parameters with position, these
measurements can be used to derive the relative distance between
the second wellbore 40 and the first wellbore 10 and the angle of
orientation of the second wellbore 40 about the first wellbore 10.
As shown in FIG. 13B, using the set of predetermined correlations
of the measured magnetic field parameters with position, the
relative distance between the second wellbore 40 and the first
wellbore 10 is determined to be substantially constant (e.g.,
5.5-5.9 meters) along the length of the second wellbore 40 from
position "A" to position "F", and the angle of orientation of the
second wellbore 40 is also determined to be substantially constant
(e.g., 310 degrees) as well, indicative of successful paralleling
of the second wellbore 40 to the first wellbore 10.
[0110] FIG. 13C schematically illustrates an example horizontal to
vertical interception configuration including a table of example
measured values of the various parameters of the magnetic field 62
from the electromagnet 60 in accordance with certain embodiments
described herein. As shown in the section view in the left bottom
portion of FIG. 13C and the side view in the middle bottom portion
of FIG. 13C, the second wellbore 40 extends downward in a generally
vertical direction generally towards the first wellbore 10
containing the electromagnet 60. At a series of positions labeled
"J" through "O" in FIG. 13C, a longitudinal axis magnetometer
within the second wellbore 40 can measure the various magnetic
field values. The values of the axial magnetic field component in
the table of FIG. 13C can be measured dynamically (e.g., during
drilling) while the values of the total magnetic field intensity,
flux angle, and cross axial magnetic field components can be
measured statically (e.g., while the drill string 30 is
stationary). Using the set of predetermined correlations of these
parameters with position, these measurements can be used to derive
the relative distance between the second wellbore 40 and the first
wellbore 10 and the angle of orientation of the second wellbore 40
about the first wellbore 10.
[0111] As shown in FIG. 13C, using the set of predetermined
correlations of the measured magnetic field parameters with
position, the region of the second wellbore 40 in closest approach
to the first wellbore 10 (e.g., between points labeled "M" and "N"
in FIG. 13C) has a relative distance between the second wellbore 40
and the first wellbore 10 between 7.8 meters and 8.1 meters. At
these two positions (e.g., where the measurements taken during
drilling) indicate the closest approach, additional measurements
can be taken while the drill string 30 is stopped to measure the
cross axial field components to get further information regarding
the relative position of the second wellbore 40 to the first
wellbore 10. While FIG. 13C shows example values for a second
wellbore 40 that passes by the first wellbore 10, similar
information can be used to steer the second wellbore 40 to
intersect the first wellbore 10 while drilling commences. In
certain embodiments in which previously-obtained measurements of
the magnetic field parameters with position are not available
(e.g., for certain passive ranging situations), the shape of the
magnetic field can be derived (e.g., determined) from
symmetry-based assumptions (e.g., symmetry about the longitudinal
axis of the wellbore casing) and using triangulation to provide a
set of predetermined correlations of the measured magnetic field
parameters with position.
[0112] In certain embodiments, upon completion of drilling the
second wellbore 40, the gyro of the at least one sensor module 20
may be used in continuous mode, static mode, or in a combination of
the two modes, while the at least one sensor module 20 is pulled
out of the second wellbore 40. In certain such embodiments, these
measurements may be used in conjunction with the gyro survey data
gathered while drilling the second wellbore 40 to generate a
definitive wellbore position or trajectory.
[0113] In certain embodiments, the current flowing through the
electromagnet 60 can be switched from one direction to the opposite
direction, thereby switching the directions of the magnetic flux
lines of the resulting magnetic field 62. By taking ranging
measurements while the current is flowing in one direction and then
the other, certain embodiments described herein are able to remove
the effect of the Earth's magnetic field from the measurements. In
certain embodiments, the components of the magnetic field sensed by
the at least one magnetometer module when current is flowing in a
first direction in the coils of the electromagnet, denoted by the
subscript 1, (H.sub.xr1, H.sub.yr1, H.sub.zr1) can be expressed as
the sum of the components of the Earth's magnetic field (H.sub.x,
H.sub.y, H.sub.z) and the components of the interference field
(H.sub.xi, H.sub.yi, H.sub.zi) as follows:
H.sub.xr1=H.sub.x+H.sub.xi
H.sub.yr1=H.sub.y+H.sub.yi
H.sub.zr1=H.sub.z+H.sub.zi
[0114] If the current in the electromagnet is reversed, the
direction of the measured interference field is reversed, and
components of the magnetic field sensed by the at least one
magnetometer module, denoted by the subscript 2, (H.sub.xr2,
H.sub.yr2, H.sub.zr2) can be expressed as follows:
H.sub.xr2=H.sub.x-H.sub.xi
H.sub.yr2=H.sub.y-H.sub.yi
H.sub.zr2=H.sub.z-H.sub.zi
The interference field can now be determined by subtracting the
second set of readings from the first set of readings and dividing
the result by two, viz.
H.sub.xi=(H.sub.xr1-H.sub.xr2)/2
H.sub.yi=(H.sub.yr1-H.sub.yr2)/2
H.sub.zi=(H.sub.zr1-H.sub.zr2)/2
[0115] These readings can then be used to compute the range and
direction to the target well as described above.
[0116] In certain other embodiments, a single magnetic ranging
survey is taken at each desired position without switching the
current of the electromagnet 60, and the Earth's magnetic field is
removed by using the gyro measurements of the azimuth, inclination,
and rotation angles, and using the magnetic dip and total magnetic
field from measurements at the rig site or derived from models
(e.g., BGGM, HDGM, etc.) (e.g., as described above, using explicit
knowledge regarding the components of the Earth's magnetic field,
such as the azimuth component). By taking only a single survey,
certain such embodiments can advantageously save time. In certain
other embodiments, two measurements with the reversal of the
current direction in the electromagnet coils, Earth's field, and
knowledge of the azimuth may not be used.
[0117] FIG. 14 is a flow diagram of an example method 500 for
gyro-assisted magnetic ranging in the context of SAGD drilling
using a rotary steerable drilling tool 30 in accordance with
certain embodiments described herein. In an operational block 510,
the method 500 comprises steering the drilling tool 30 to a
position at which a magnetic field 62 from an electromagnet 60 in
the first wellbore 10 (e.g., the target wellbore) can be detected
by at least one sensor module 20 of the drilling tool 30. For
example, the electromagnet 60 (e.g., solenoid) can be positioned
within the first wellbore 10 at a location at which the second
wellbore 40 is to begin "twinning" to the first wellbore 10, and
the drilling tool 30 can be steered to a position sufficiently
close to the electromagnet 60 such that the at least one sensor
module 20 detects the magnetic field 62.
[0118] In an operational block 520, the method 500 further
comprises performing a multi-station analysis to detect BHA biases.
In certain embodiments, performing the multi-station analysis in
the operational block 520 can occur while steering the drilling
tool 30 to the position in the operational block 510. The detected
BHA biases can be used subsequently in the method 500 as described
more fully below.
[0119] In an operational block 530, the method 500 further
comprises monitoring measurements from a longitudinal axis
magnetometer of the at least one sensor module 20 as the drill path
of the second wellbore 40 approaches the electromagnet 60 in the
first wellbore 10. For example, the electromagnet 60 may be
activated once, twice, or more, and can be activated for a
predetermined period of time (e.g., 40 seconds). In certain
embodiments, monitoring the measurements from the longitudinal axis
magnetometer comprises determining an angle of interception (e.g.,
a slant range) and a direction of the at least one sensor module 20
with respect to the electromagnet 60. In certain such embodiments,
determining the angle of interception and the direction comprises
using the detected BHA biases to correct the measurements from the
longitudinal axis magnetometer (e.g., to remove the BHA biases) and
using knowledge of the Earth's field (e.g., in conjunction with
gyroscopic measurements of azimuth of the at least one sensor
module 20) to correct the measurements from the longitudinal axis
magnetometer (e.g., to remove the contributions from the Earth's
magnetic field).
[0120] In an operational block 540, the method 500 further
comprises making stationary magnetic ranging survey measurements
using the at least one sensor module 20. Making the measurements
can comprise halting drilling of the second wellbore 40 upon the at
least one sensor module 20 reaching a predetermined location with
respect to the electromagnet 60. For example, the drilling of the
second wellbore 40 can be halted upon the at least one sensor
module 20 reaching the first switch point, as discussed herein, and
then the stationary magnetic ranging survey measurements can be
made while the at least one sensor module 20 is at the first switch
point. In certain embodiments, making the stationary magnetic
ranging survey measurements comprises using the detected BHA biases
and the knowledge of the Earth's magnetic field at the azimuth of
the at least one sensor module 20 to correct the stationary
magnetic ranging survey measurements.
[0121] In an operational block 550, the method 500 further
comprises moving the electromagnet 60 to a different position
within the first wellbore 10. For example, the electromagnet 60 can
be advanced to a position a predetermined distance (e.g., 96
meters) further down the first wellbore 10.
[0122] In an operational block 560, the method 500 further
comprises making magnetic ranging measurements and further drilling
the second wellbore 40 in a trajectory that is substantially
parallel to the first wellbore 10. In certain embodiments, the
magnetic ranging measurements are used to compute drilling commands
to be performed by the drilling tool 30 to advance a predetermined
distance (e.g., sufficient for the creation of the next wellbore
section; an example of which includes 11-13 meters) in the
trajectory substantially parallel to the first wellbore 10.
[0123] In an operational block 570, the method 500 further
comprises making stationary gyro survey measurements using the at
least one sensor module 20 and using the stationary gyro survey
measurements in determining a separation and angle of approach of
the at least one sensor module 20 to the first wellbore 10. Making
the measurements can comprise halting drilling of the second
wellbore 40 upon reaching the predetermined distance.
[0124] In an operational block 580, the method 500 further
comprises using the stationary gyro survey measurements to compute
drilling commands to be performed by the drilling tool 30 to
advance a predetermined distance (e.g., sufficient for the creation
of the next wellbore section; an example of which includes 11-13
meters) and continuing the drilling of the second wellbore 40.
[0125] The method 500 can further comprise iterating the
operational blocks 560-580 (denoted in FIG. 14 by the arrow 590)
until the magnetic field 62 from the electromagnet 60 is again
detected. The method 500 can further comprise iterating the
operational blocks 530-580 (denoted in FIG. 14 by the arrow 592)
for drilling subsequent sections (e.g., 96 meters) of the second
wellbore 40.
[0126] Conditional language used herein, such as, among others,
"can," "could," "might," "may," "e.g.," and the like, unless
specifically stated otherwise, or otherwise understood within the
context as used, is generally intended to convey that certain
embodiments include, while other embodiments do not include,
certain features, elements and/or states. Thus, such conditional
language is not generally intended to imply that features, elements
and/or states are in any way required for one or more embodiments
or that one or more embodiments necessarily include logic for
deciding, with or without author input or prompting, whether these
features, elements and/or states are included or are to be
performed in any particular embodiment.
[0127] Depending on the embodiment, certain acts, events, or
functions of any of the methods described herein can be performed
in a different sequence, can be added, merged, or left out
completely (e.g., not all described acts or events are necessary
for the practice of the method). Moreover, in certain embodiments,
acts or events can be performed concurrently, e.g., through
multi-threaded processing, interrupt processing, or multiple
processors or processor cores, rather than sequentially.
[0128] The various illustrative logical blocks, modules, circuits,
and algorithm steps described in connection with the embodiments
disclosed herein can be implemented as electronic hardware,
computer software, or combinations of both. To clearly illustrate
this interchangeability of hardware and software, various
illustrative components, blocks, modules, circuits, and steps have
been described above generally in terms of their functionality.
Whether such functionality is implemented as hardware or software
depends upon the particular application and design constraints
imposed on the overall system. The described functionality can be
implemented in varying ways for each particular application, but
such implementation decisions should not be interpreted as causing
a departure from the scope of the disclosure.
[0129] The various illustrative logical blocks, modules, and
circuits described in connection with the embodiments disclosed
herein can be implemented or performed with a general purpose
processor, a digital signal processor (DSP), an application
specific integrated circuit (ASIC), a field programmable gate array
(FPGA) or other programmable logic device, discrete gate or
transistor logic, discrete hardware components, or any combination
thereof designed to perform the functions described herein. A
general purpose processor can be a microprocessor, but in the
alternative, the processor can be any conventional processor,
controller, microcontroller, or state machine. A processor can also
be implemented as a combination of computing devices, e.g., a
combination of a DSP and a microprocessor, a plurality of
microprocessors, one or more microprocessors in conjunction with a
DSP core, or any other such configuration.
[0130] The blocks of the methods and algorithms described in
connection with the embodiments disclosed herein can be embodied
directly in hardware, in a software module executed by a processor,
or in a combination of the two. A software module can reside in RAM
memory, flash memory, ROM memory, EPROM memory, EEPROM memory,
registers, a hard disk, a removable disk, a CD-ROM, or any other
form of computer-readable storage medium known in the art. An
exemplary tangible, computer-readable storage medium is coupled to
a processor such that the processor can read information from, and
write information to, the storage medium. In the alternative, the
storage medium can be integral to the processor. The processor and
the storage medium can reside in an ASIC. The ASIC can reside in a
user terminal. In the alternative, the processor and the storage
medium can reside as discrete components in a user terminal.
[0131] While the above detailed description has shown, described,
and pointed out novel features as applied to various embodiments,
it will be understood that various omissions, substitutions, and
changes in the form and details of the devices or algorithms
illustrated can be made without departing from the spirit of the
disclosure. As will be recognized, certain embodiments described
herein can be embodied within a form that does not provide all of
the features and benefits set forth herein, as some features can be
used or practiced separately from others. The scope of certain
inventions disclosed herein is indicated by the appended claims
rather than by the foregoing description. All changes which come
within the meaning and range of equivalency of the claims are to be
embraced within their scope.
* * * * *
References