Note: Descriptions are shown in the official language in which they were submitted.
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1594P16CA01
MAGNETIC FIELD ENHANCEMENT
FOR USE IN PASSIVE RANGING
Inventor: Graham A. McElhinney
44 High Street, Inverurie
Aberdeenshire, Scotland
United Kingdom
Citizenship: U,K.
FIELD OF THE INVENTION
[OOO1J The present invention relates generally to surveying a subterranean
borehole to
determine, for example, the path of the borehole. More particularly this
invention relates
to a method of passive ranging to determine directional and/or locational
parameters of a
borehole using sensors including one or more magnetic field measurement
devices.
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2
BACKGROUND OF THE INVENTION
[0002] The use of magnetic field measurement devices (e.g., magnetometers) in
prior
art subterranean surveying techniques for determining the direction of the
earth's
magnetic field at a particular point is well known. The use of accelerometers
or
gyroscopes ixz combination with one or more magnetometers to determine
direction is also
known. Deployments of such sensor sets are well known to determine borehole
characteristics such as inclination, azimuth, positions in space, tool face
rotation,
magnetic tool face, and magnetic azimuth (i.e., an azimuth value determined
from
magnetic field measurements). While magnetometers are known to provide
valuable
information to the surveyor, their use in borehole surveying, and in
particular
measurement while drilling (MWD) applications, tends to be limited by various
factors.
For example, magnetic interference, such as from the magnetic steel components
(e.g.,
liners, casings, etc.) of an adjacent borehole (also referred to as a target
well herein) tends
to interfere with the earth's magnetic field and thus may cause a deflection
in the azimuth
values obtained from a magnetometer set.
[0003] Passive ranging techniques may utilize such magnetic interference
fields, for
example, to help determine the location of an adjacent well (target well) to
reduce the risk
of collision and/or to place the well into a kill zone (e.g., near a well blow
out where
formation fluid is escaping to an adjacent well). U.S. Patent 5,675,488 and
U.S. Patent
Applications 10/368,257, 10/368,742, and 10/369,353 to McElhinney (herein
referred to
as the McElhinney patents) describe methods for determining the position of a
target well
with respect to a measured well (e.g., the well being drilled) in close
proximity thereto.
Such methods utilize three-dimensional magnetic interference vectors
determined at a
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3
number of points in the measured well to determine azimuth and/or inclination
of the
target well and/or the distance from the measured well to the target well.
[0004] The methods described in the McElhinney patents have been shown to work
well in a number of borehoie surveying applications, such as, for example;
well avoidance
and or well kill applications. However, there remain certain other
applications for which
improved passive ranging techniques may advantageously be utilized. For
example, well
twinning applications (in particular in near horizontal well sections), in
which a measured
well is drilled essentially parallel to a target well, may benefit from such
improved
passive ranging techniques.
[0005] Moreover, well twinning in steam assisted gravity drainage applications
may
particularly benefit from improved passive ranging techniques. Currently,
active ranging
techniques, for example, in which high strength electromagnets are snaked
through a
target well during drilling of the twin well, are utilized in such
applications. However
simultaneous operation of the electromagnetic assembly in the target well and
the drilling
assembly in the twin well tends to be both expensive and awkward.
Additionally, active
ranging techniques typically do not account for magnetic interference and are
therefore
further susceptible to error.
[0006] Therefore, there exists a need for improved borehole surveying methods
utilizing various passive ranging techniques.
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SIJ1VIMARY OF THE INVENTION
(0007] Exemplary aspects of the present invention are intended to address the
above
described need for improved surveying methods utilizing various passive
ranging
techniques. Referring briefly to the accompanying figures, aspects of this
invention
include methods for surveying a borehole. Such methods make use of magnetic
flux
emanating from nearby magnetized subterranean structures (typically referred
to herein as
target wells), such as cased boreholes. Such magnetic flux may be passively
measured to
determine a direction and distance from the borehole being surveyed (also
referred to
herein as the measured well) to the target well. In various exemplary
embodiments, the
orientation of the measured well relative to the target well, the distance
between the two
wells, and the absolute coordinates, and the azimuth of the measured well may
also be
determined.
[0008] Exemplary embodiments of the present invention advantageously provide
several technical advantages. For example, the direction and distance from a
measured
well to a target well may advantageously be determined without having to
reposition the
downhole tool in the measured well. Further, embodiments of this invention may
be
utilized to determine an azimuth value of the measured well. Such azimuth
determination
may be advantageous in certain drilling applications, such as in regions of
magnetic
interference where magnetic azimuth readings are often unreliable. Aspects of
this
invention may also advantageously be utilized in certain drilling
applications, such as
well twinning and/or relief well applications, to guide continued drilling of
the measur~l
well, for example, in a direction substantially parallel wii:h the target
well. Exemplary
embodiments of this invention may be advantageously utilized for drilling twin
wells for
steam assisted gravity drainage applications.
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In one exemplary aspect the present invention includes a method for surveying
a
borehole. The method includes providing a casing string in a target borehole,
the casing
string including a plurality of opposing magnetic poles. The method further
includes
providing a downhole tool including first and second magnetic field
measurement devices
disposed at corresponding first and second positions in the borehole. The
first and second
positions are selected to be within sensory range of magnetic flux from the
casing string.
The method further includes measuring total local magnetic fields at the first
and second
positions using the corresponding first and second magnetic field measurement
devices,
processing the total local magnetic fields at the first and second positions
and a reference
magnetic field to determine a portion of the total local magnetic fields
attributable to the
casing string, and generating interference magnetic field vectors at the first
and second
positions from the portion of the total local magnetic field attributable to
the casing string.
The method further includes processing the interference magnetic field vectors
to
determine tool face to target angles at each of the first and second
positions.
[0009] The foregoing has outlined rather broadly the features and technical
advantages
of the present invention in order that the detailed description of the
invention that follows
may be better understood. Additional features and advantages of the invention
will be
described hereinafter which form the subject of the claims of the invention.
It should be
appreciated by those skilled in the art that the conception and the specific
embodiment
disclosed may be readily utilized as a basis for modifying or designing other
structures for
carrying out the same purposes of the present invention. It should be also be
realize by
those skilled in the art that such equivalent constructions do not depart from
the spirit and
scope of the invention as set forth in the appended claims.
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BRIEF DESCRIPTION OF THE DRAWINGS
[4010] For a more complete understanding of the present invention, and the
advantages
thereof, reference is now made to the following descriptions taken in
conjunction with the
accompanying drawings, in which:
[0011] FIGURE 1 is a schematic representation of an exemplary embodiment of a
MWD tool according to the present invention including both upper and lower
sensor sets.
[0012] FIGURE 2 is a diagrammatic representation of a portion of the MWD tool
of
FIGURE 1 showing unit magnetic field and gravity vectors.
[0013] FIGURES 3A and 3B are schematic representations of an exemplary
application
of this invention.
[0014] FIGURES 4A through 4D depict exemplary target well casing
configurations.
[0015] FIGURES SA and SB depict contour plots of a theoretical magnetic flux
density
about hypothetical casing strings.
[0016] FIGURE 6 depicts the theoretical magnetic field strength versus
measured well
depth along portions of the casing strings shown in FIGURES SA and SB.
[001'1] FIGURE 7 is a schematic representation of a cross sectional view along
section
4-4 of FIGURE 3B.
[0018] FIGURE 8 is a schematic representation of a hypothetical plot of tool
face to
target versus well depth as an illustrative example of one embodiment of this
invention.
[00191 FIGURE 9 depicts a cross sectional view similar to that of FIGURE 4 as
an
illustrative example of various embodiments ofthis invention.
[0020) FIGURES l0A and lOB depict cross sectional views similar to those of
FIGURES 4 and 6 as illustrative examples of other embodiments of this
invention.
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[0021] FIGURE 11 depicts a cross sectional view similar to that of FIGURES 5,
7, 8A
and 8B as an illustrative example of still other exemplary embodiments of this
invention.
[0022} FIGURE 12 is a display of a drilling plan for a hypothetical well
twinning
operation.
[0023] FIGURE 13 is another diagrammatic representation of a portion of the
1VIWD
tool of FIGURE 1 showing the change in azimuth between the upper and lower
sensor
sets.
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g
DETAILED DESCRIPTION
[0024] Referring now to FIGURE 1, one exemplary embodiment of a downhole tool
100 useful in conjunction with the method of the present invention is
illustrated. In
FIGURE 1, downhole tool 100 is illustrated as a measurement while drilling
(MWD) tool
including upper 110 and lower 120 sensor sets coupled to a bottom hole
assembly (BHA)
150 including, for example, a steering tool 154 and a drill bit assembly 158.
The upper
110 and lower 120 sensor sets are disposed at a known spacing, for example, on
the order
of from about 2 to about 20 meters (i.e., about 6 to about 60 feet). Each
sensor set (114
and 120) includes at least two (and preferably three) mutually orthogonal
magnetic field
sensors, with at least one magnetic field sensor in each set having a known
orientation
with respect to the borehole, and three mutually orthogonal gravity sensors.
It will be
appreciated that the method of this invention may also be practiced with a
downhole tool
including only a single sensor set having at least two magnetic field sensors.
[0025] Referring now to FIGURE 2, a diagrammatic representation of a portion
of the
MWD tool of FIGURE 1 is illustrated. In the embodiment shown on FIGURES 1 and
2,
each sensor set includes three mutually perpendicular magnetic field sensors,
one of
which is oriented substantially parallel with the borehole and measures
magnetic field
vectors denoted as Bzl and Bz2 for the upper 110 and lower 120 sensor sets,
respectively.
The upper 110 and lower 120 sensor sets are linked by a structure 140 (e.g., a
semi-rigid
tube such as a portion of a drill string) that permits bending along its
longitudinal axis 50,
but substantially resists rotation between the upper 110 and lower 120 sensor
sets along
the longitudinal axis 50. Each set of magnetic field sensors thus may be
considered as
determining a plane (Bx and By) and pole (Bz) as shown. As described in more
detail
below, embodiments of this invention typically only require magnetic field
measurements
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9
in the plane of the tool face (Bx and By as shown in FIGURE 2 which
corresponds with
plane 121, for example, in sensor set 120}. T'he structure 140 between the
upper 110 and
lower 120 sensor sets may advantageously be part of, for example, a MWD tool
as shown
above in FIGURE 1. Alternatively, structure 140 may be a part of substantially
any other
logging and/or surveying apparatuses, such as a wireline surveying tool.
[0026] As described above, embodiments of this invention may be particularly
useful,
for example, in well twinning applications (e.g., relief well drilling), such
as that shown
in FIGURES 3A and 3B. Generally speaking twinning refers to applications in
which
one well is drilled in close proximity (e.g., parallel) to another well for
various purposes.
Relief well drilling generally refers to an operation in which one will is
drilled to
intercept another well (e.g., to prevent a blow). Nevertheless, the terms
twinning and
relief well will be used synonymously and interchangeably in this disclosure.
In FIGURE
3A, a bottom hole assembly 150 is kicked off out of a casing window 178 in a
pre-
existing borehole 175. "Kicking off' refers to a quick change in the angle of
a borehole,
and may be associated, for example with drilling a new hole from the bottom or
the side
of an existing borehole. A relief well 177, for example, is then drilled
substantially
parallel with the pre-existing borehole 175, as shown in FIGURE 3B. In such
applications there tends to be significant magnetic interference emanating
from the pre
existing borehole 175, e.g., from the well casing, owing, for example, to
residual
magnetization from magnetic particle inspection procedures. Normally, such
magnetic
interference fades (decreases) quickly as the distance to the pre-existing
borehole
increases. However, in relief well applications, for example, in which the
distance
between the relief well 177 and the pre-existing borehole 175 typically
remains small
(e.g., from about 1 to about IO feet); such magnetic interference tends to
significantly
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interfere with the determination of borehole azimuth using conventional
magnetic
surveying techniques. Further, such relief well drilling applications are
often carried out
in near horizontal wells (e.g., to divert around a portion of a pre-existing
borehole that is
blocked or has collapsed). Thus conventional gyroscope and gravity azimuth
surveying
methods may be less than optimal for borehole surveying in such applications.
As
described in more detail below, this invention looks to the magnetic
interference from a
target well (e.g., pre-existing borehole 175) to determine the azimuth of the
measured
well (e.g., relief well 177). Surveying according to the present invention may
thus be
useful in such relief well and/or well twinning applications. Other exemplary
applications may include, but are not limited to, river crossings in which an
existing well
is followed around various obstacles, re-entry and/or well kill applications,
well
avoidance applications, and substantially any application in which multiple
substantially
parallel wells are desirable (such as also useful in mineral extraction and
ground freeze
applications).
[0027] Certain exemplary embodiments of this invexition may also be useful in
twinning wells for heavy oil recovery applications, such as steam assisted
gravity
drainage applications. In such applications, twin horizontal wells having a
vertical
separation distance ranging from about 4 to about 20 meters are typically
utilized. Steam
is injected into the upper well to heat the heavy oil. The heated heavy oil
and condensed
steam are then produced from the lower well. The success of such heavy oil
recovery
techniques is often dependent upon maintaining a predetermined relative
positioning of
the wells in he injection/production zone (which may be up to several thousand
feet in
length). As such, exemplary embodiments of this invention, as described
herein, may be
particularly advantageous for the above described heavy oil recovery
applications.
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[0028] It should be noted that the magnetic interference may emanate from
substantially any point or points on the target well. It may also have
substantially any
field strength and be oriented at substantially any angle to the target well,
with the field
strength at a particular location generally decreasing with distance from the
target
borehole. Further, the magnetic interference tends to be caused by the tubular
elements in
the target well, e.g., the casing, drill string, collars, and the like. The
magnetic
interference surrounding these elements is determined by the magnetism (both
induced
and permanent) in the metal. The shape of the interference pattern is
particularly
influenced by the homogeneity of the magnetism and the shape of the metal
element.
Typically, the magnetism is substantially homogeneous and the shape
rotationally
symmetrical and tubular. Objects in a borehole, such as pipe sections and the
like, are
often threadably coupled to form a substantially continuous cylinder. Thus,
the origin of
any magnetic interference emanating from a borehole may generally be
considered to
originate in cylinders therefrom. The magnetic field ern. anating from such a
borehole
(target well) is typically caused by such cylinders in a manner typically
displayed by
cylindrical magnets. Such is the basis for the passive ranging techniques
disclosed in the
McElhinney patents.
[0029] It will be appreciated that the terms magnetic flux density and
magnetic field are
used interchangeably herein with the understanding that they are substantially
proportional to one another and that the measurement of either may be
converted to the
other by known mathematical calculations.
[0030] As described in more detail herein, this invention looks to the
magnetic
interference emanating from a target well; caused, for example, by residual
magnetization
from magnetic particle inspection procedures. In certain applications, such as
the above
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described heavy oil recovery applications, it may be advantageous to enhance
the flux
density of the magnetic field emanating radially outward from the target well
and
therefore to increase the effective distance of the passive ranging techniques
described
herein. It has been found that the flux density may be essentially focused
radially
outward from the target well, for example, by configuring the casing string to
include a
plurality of opposing magnetic poles (i.e., magnetic poles on certain
individual casing
joints oppose magnetic poles on certain other adjacent casing joints).
Exemplary target
well casing configurations are shown on FIGURES 4A through 4D, which
illustrate
exemplary casing strings 190, 190', 190" and 190"', each including a plurality
of
magnetized casing joints 192 joined end to end. As shown, the casing strings
may be
configured to include opposing north (N) and south (S) poles at various
intervals. In
casing string 190 (FIGURE 4A), each seem 193 between individual casing joints
192
includes opposing NN or SS poles. In casing string 190' (FIGURE 4B), every
other seem
193 includes opposing NN or SS poles, while in casing sizing 190" (FIGURE 4C)
every
third seem 193 includes opposing NN or SS poles. Casing string 190"' (FIGURE
4D)
does not include any opposing NN or SS poles and is shown for comparison
purposes. It
will be appreciated that substantially any casing string configuration
including a pluratilh
of opposing magnetic poles may be utilized in the target well, for example, to
maximize
the flux density at certain longitudinal positions or intervals along the
target well.
[0031] The magnitude of the magnetic flux enhancement may be modeled using
conventional finite element analysis methods. FIGURES SA and SB show gray-
scale
contours of the flux density (black being highest and while being lowest)
about
exemplary casing string configurations and thus may be utilized to compare and
contrast
the magnetic field strength about those casing strings. In FIGURE SA, the
casing string
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includes opposing magnetic poles at every third seam as shown in FIGURE 4C. In
FIGURE SB, the casing string includes no opposing magnetic poles. Rather the
magnetic
poles on the individual casing joints are aligned as shown in FIGURE 4D (e.g.,
with the
magnetic north poles on the uphole side of each casing joint and the magnetic
south poles
on the downhole side of each casing joint). In each model, a casing string
including 27
casing joints was utilized. The magnetic pole strengths were configured to
vary randomly
from one joint to the next in a manner consistent with known magnetic field
strengths for
such casing joints. Further, in this exemplary model, each casing joint was 13
meters in
length by 0.6 meters in diameter, which is consistent with upper well
dimensions in some
steam assisted gravity dxainage applications. It will be appreciated that this
invention is
not limited by such model assumptions.
[0032] As shown by contrasting FIGURES SA and SB, including regular opposing
magnetic poles in the casing string surprisingly significantly enhances the
magnetic field
strength (which is proportional to the magnetic flux density) about target
well. It will be
appreciated that in this exemplary model the magnetic flux enhancement is due
only to
the opposing magnetic poles. As expected, the magnetic field strength includes
maxima
near the opposing poles (also shown below in FIGURE 6). However, contrary to
conventional wisdom, the magnetic field strength is significantly enhanced
along the
entire casing string as compared to a casing string including no opposing
poles. Tt will
also be appreciated that such significant enhancements are not limited to the
examples
shown in FIGURES 4A through 5B. Rather, it has been faund that that the
magnetic field
about substantially any casing string having a plurality of opposing magnetic
poles is
significantly enhanced as compared to a casing string that does not include
opposing
magnetic poles.
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[0033] With reference now to FIGURE 6, the magnetic field strength versus
measured
depth (longitudinal position along the casing string) is shown at a radial
distance of 6
meters. The magnetic field strength of the casing having opposing poles (e.g.,
casing
190" shown on FIGURE 4C) is shown at 196 while the magnetic field strength of
the
casing having no opposing poles (e.g., casing 190"' on FIGURE 4D) is shown at
198. It
can be seen that configuring the casing string to include opposing poles every
third seam
increases the magnetic field strength by up to about five times. Such a
pronounced
increase in magnetic field strength advantageously increases the distance over
which the
passive ranging techniques described herein may be successfully utilized
(e.g., up to
about 20 meters in some applications). Increased magnetic field strength also
tends to
advantageously reduce errors associated with such passive ranging
measurements, for
example, via increasing the signal to noise ratio of the measured magnetic
fields values
(magnetometer readings).
[0034] In practice, casing strings having a plurality of opposing poles may be
made up
using substantially any procedure. For example, individual casing joints may
be "cherry-
picked" at the casing yard or at the rig site based on known magnetic
properties of the
individual casing joints (e.g., obtained via on-site magnetic measurements).
For example,
two joints having magnetic north poles near their respective pin ends may be
chosen first,
followed by two joints having magnetic south poles near their respective pin
ends, and so
on to make up a casing string as shown in FIGURE 4B (casing string 190').
Alternatively, the individual casing joints may be magnetized (Gaussed up)
with
predetermined magnetic pole strengths and locations prior to being made up
into the
casing string. Such magnetization may be independent of or in cooperation with
conventional particle inspection techniques.
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[0035] It may also be advantageous on occasion to attach various magnetic
sources,
such as ring, spherical, cylindrical, and/or rod magnets to the casing string.
Such
magnetic sources may enhance the local magnetic field about the target well
and assist a
drilling operator in orienting andlor aligning the measured well with respect
to the target
well.
(0036] The magnetic interference may be measured as a vector whose orientation
depends on the location of the measurement point within the magnetic field. In
order to
determine the magnetic interference vector at any point downhole, the magnetic
field of
the earth must be subtracted from the measured magnetic field vector. The
magnetic field
of the earth (including both magnitude and direction components) is typically
known, for
example, from previous geological survey data. However, for some applications
it may
be advantageous to measure the magnetic field in real time on site at a
location
substantially free from magnetic interference, e.g., at the surface of the
well or in a
previously drilled well. Measurement of the magnetic field in real time is
generally
advantageous in that in that it accounts for time dependent variations in the
earth's
magnetic field, e.g., as caused by solar winds. However, at certain sites,
such as on an
offshore drilling rig, measurement of the earth's magnetic field in real time
may not be
possible. In such instances, it may be preferable to utilize previous
geological survey data
in combination with suitable interpolation and/or mathematical modeling (i.e.,
computer
modeling) routines.
[0037] The earth's magnetic field at the tool may be expressed as follows:
M~ =HE(cosDsinAzcosR+cosDcosAzcoslhcsinR-sinDsinlncsinR)
M~, =HE(cosDcosAzcoslnccosR+sinDsinlnccosR-cosDsinAzsinR)
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MEZ = HE (sin D cos Inc - co s D cos Az sin Inc) Equation 1
where Mex, Mey, and Mez represent the x, y, and z components, respectively, of
the
earth's magnetic field as measured at the downhole tool, where the z component
is
aligned with the borehole axis, He is known (or measured as described above)
and
represents the magnitude of the earth's magnetic field, and D, which is also
known (or
measured), represents the local magnetic dip. Inc, Az, and R, represent the
Inclination,
Azimuth and Rotation (also known as the gravity tool face), respectively, of
the tool,
which may be obtained, for example, from conventional gravity surveying
techniques.
However, as described above, in various relief well applications, such as in
near
horizontal wells, azimuth determination from conventional surveying techniques
tends to
be unreliable. In such applications, since the measured borehole and the
target borehole
are essentially parallel (i.e., within a five or ten degrees of being
parallel), Az values .from
the target well, as determined, for example in a historical survey, may be
utilized.
The magnetic interference vectors may then be represented as follows:
M~ = BX - M~
MIY = BY - MEY
M~ = BZ -MEZ Equation 2
where Mix, Miy, and Miz represent the x, y, and z components, respectively, of
the magnetic interference vector and Bx, By, and Bz, as described above,
represent the
measured magnetic field vectors in the x, y, and z directions, respectively.
[0038] The artisan of ordinary skill will readily recognize that in
determining the
magnetic interference vectors it may also be necessary to subtract other
magnetic field
components, such as drill string and/or motor interference from the borehole
being
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drilled, from the measured magnetic field vectors. Techniques for accounting
for such
other magnetic field components are well known in the art.
[0039] Referring now to FIGURES 7 through 12, embodiments of the method of
this
invention are described in further detail. With reference to FIGURE 7, a cross
section as
shown on FIGURE 3B is depicted looking down the target borehole 175. Since the
measured borehole and the target borehole are approximately parallel, the view
of
FIGURE 7 is also essentially looking down the measured borehole. The magnetic
flux
lines 202 emanating from the target borehole 175 are shown to substantially
intersect the
target borehole 175 at a point T. Thus a magnetic field vector 205 determined
at the
measured borehole 1~7, for example, as determined by Equations 1 and 2 above,
provides
a direction from the measured borehole to the target borehole 175. Since the
measured
borehole and the target borehole are typically essentially parallel,
determination of a two-
dimensional magnetic field vector (e.g., in the planes of the tool faces 111
and 121 shown
in FIGURE 2) and a two-dimensional interference vector is advantageously
sufficient for
determining the direction from the measured well to the target well. Two-
dimensional
magnetic field and interference vectors may be determined according to
Equations 1 and
2 by solving for Mex, Mey, Mix, and Miy. As such measurement of the magnetic
fzeld in
two dimensions (e.g., Bx and By) may likewise be sufficient for determining
the direction
from the measured well to the target well. Nevertheless, for certain
applications it may be
preferable to measure the magnetic field in three dimensions.
[0040} A tool face to target (TFT) value (also referred to herein as a tool
face to target
angle) may be determined from the magnetic interference vectors given in
Equation 2 as
follows:
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TFT = arctan(~'~ ) + arctan( ~'x ) Equation 3
err GY
[0041] where TFT represents a tool face to target direction (angular
orientation), Mix
and Miy represent the x and y components, respectively, of the magnetic
interference
vector, and Gx and Gy represent x and y components of the measured
gravitational field
(e.g., gravity vectors measured at at least one of the first and second sensor
sets 110, 120
in FIGURE 2). As shown in FIGURE 5, the TFT indicates the direction from the
measured well 177 to the target well 175. For example, a TFT of 90 degrees, as
shown in
FIGURE 7, indicates that the target well 175 is directly to the right of the
measured well
177. A TFT of 270 degrees, on the other hand, indicates that the target well
is directly to
the left of the measured well. Further, at TFT values of 0 and 180 degrees the
target well
175 is directly above and directly below, respectively, the measured well 177.
It will be
appreciated that in certain applications, Equation 3 does not fully define the
direction
from the measured well 177 to the target well 175. Thus in such applications,
prior
knowledge regarding the general direction from the measured well to the target
well (e.g.,
upwards, downwards, left, or right) may be utilized in combination with the
TFT values
determined in Equation 3. Alternatively, changes in the TFT values between
adjacent
survey points may be utilized to provide further indication of the direction
from the
measured well 177 to the target well 175.
[0042] In certain applications, determination of the TFT at two or more points
along
the measured well bore may be sufficient to guide continued drilling of the
measured
well, for example, in a direction substantially parallel with the target well.
This is shown
schematically in FIGURE 8, which plots 250 TFT 252 versus Well Depth 254. Data
sets
262, 264, 266, and 268 represent TFT values determined at various well depths.
Each
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Y
data set, e.g., data set 262, includes two data points, A and B, determined at
a single
survey location (station). In data set 262, for example, data point A is the
TFT value
determined from the magnetic interference vector measured at an upper sensor
set (e.g.,
sensor set 110 in FIGURES 1 through 3B) and data point B is the TFT value
determined
from the magnetic interference vector measured at a lower sensor set (e.g.,
sensor set 120
in FIGURES 1 through 3B), which resides some fixed distance (e.g., from about
6 to
about 60 feet) further down the borehole than the upper sensor set. Thus at
each survey
station (data sets 262, 264, 266, and 268) two magnetic interference vectors
may be
determined. The TFT at each data point indicates the direction to the target
borehole
from that point on the measured borehole. Additionally, and advantageously for
MWD
embodiments including two sensor sets, comparison of the A and B data points
at a given
survey station (e.g., set 262) indicates the relative direction of drilling
with respect to the
target well at the location of that survey station. Further, since a drill bit
is typically a
known distance below the lower sensor set, the TFT at the drill bit may be
determined by
extrapolating the TFT values from the upper and lower sensor sets (points A
and B on
FIGURE 6).
[0043] With continued reference to FIGURE 8, data sets 262, 264, 266, and 268
are
described in more detail. In this hypothetical example, data sets 262, 264,
266, and 268
represent sequential survey stations (locations) during an MWD drilling
operation and
thus may be spaced at a known interval (e.g., about 50 feet) in the measured
well. At data
set 262, the target well is down and to the right of the measured well as
indicated by the
TFT values. Since the TFT at point B is closer to 90 degrees than that of
point A, data set
262 indicates that the measured well is pointing downward relative to the
target well. For
a drilling operation in which it is intended to drill the measured well
parallel and at the
CA 02460788 2004-03-12
same vertical depth as the target well (e.g., at a TFT of 90 degrees), data
set 262 would
indicate that drilling should continue for a time in approximately the same
direction. At
data set 264, the measured well has moved below the target well as indicated
by TFT
values below 90 degrees. Similar TFT values for points A and B indicate that
the
measured MWD tool (and therefore the measured well) is pointed horizontally
relative to
the target well. At data set 266, the measured well remains below the target
well, but is
pointing upward relative thereto. And at data set 268, the measured well is at
about the
same vertical depth as the target well and substantially aligned therewith
vertically.
[0044] While tool face to target values determined from the magnetic
interference
vectors provide potentially valuable directional information relating to the
position of a
measured well relative to a target well, they do not, alone, provide an
indication of the
distance from the measured well to the target well. According to one aspect of
this
invention, the TFT values m~,y be utilized, along with survey data from the
measured well
(e.g., inclination values) and historical survey data from the target well, to
determine a
distance from the measured well to the target well. In one variation of this
aspect, the
direction and distance from the measured well to the target well may then be
utilized to
determine absolute coordinates and azimuth values for the measured well at
various
points along the length thereof.
[0045] With reference now to FIGURE 9, a view down the target borehole,
similar to
that of FIGURE 7, is shown. It will be appreciated that for near horizontal
wells, the x
and y directions in FIGURE 9 correspond essentially to horizontal and vertical
directions
relative to the target well 175. At first and second survey points 177, 177'
(e.g., as
measured at sensor sets 110 and 120, respectively, as shown in FIGURES 1
through 3B)
the measured borehole is generally downward and to the left of target borehole
175, as
CA 02460788 2004-03-12
21
shown. As described above, this is indicated by the TFT values TFT1, TFT2 at
the two
survey points being less than 90 degrees. In the general case illustrated in
FIGURE 9, the
measured well 177, 177' is not precisely parallel with the target well 175. As
such, the
relative position of the measbred well with respect to the target well 175 (in
the view of
FIGURE 9) is a function of the measured depth of the measured well (as shown
by the
relative change in position between the two wells at the first and second
survey points
177, 177'). Such a change in the relative position at the first and second
survey points
177, 177' is represented by ax and 0y in FIGURE 9, where Ox represents the
relative
change in horizontal position between the first and second survey points 177,
177' of the
measured well and corresponding points on the target well 175 (e.g.,
substantially
orthogonal to the longitudinal axis of the measured well at the first and
second survey
points), and Dy represents the relative change in vertical position between
the first and
second survey points 177, 177' of the measured well and corresponding points
on the
target well 175. As described above, in many instances the relative change in
positions
between the two wells (as defined by ~x and ~y) results in a change in the
measured tool
face to target value, ~TFT, between the first and second survey points 177,
177'. As
described in greater detail below, for certain applications, the distances dl
and d2 from
the first and second survey points 177, 177' on the measured well to the
target well 175
are approximately inversely proportional to OTFT.
[0046] It will be appreciated that based on FIGURE 9 and known trigonometric
principles, the distances dl and d2 may be determined mathematically, for
example, from
fix, ~y, TFT1 and TFT2. With continued reference to FIGURE 9, and according to
the
Pythagorean Theorem, distances dl and d2 may be expressed mathematically as
follows:
CA 02460788 2004-03-12
22
dl= x2 +(y-Dy)2
d 2 = (x - t1x) 2 + y 2 Equation 4
[0047] where x and y represent the horizontal distance from the first survey
point 177
to the target well 175 and the vertical distance from the second survey point
177' to the
target well 175, respectively. x and y may be expressed mathematically as
follows:
- ~x tan(TFTI) - 4y tan(TFTI) tan(TFT 2)
x=
tan(TFT 2) - tan(TFTl)
_ - Dy tan(TFT I) - 0x
y tan(TFT2) - tan(TFTl) Equation 5
[0048] where, as described above, ~x represents the relative change in
horizontal
position between the first and second survey points 177, 177' of the measured
well and
corresponding points on the target well 175, ~y represents the relative change
in the
vertical position between the first and second survey points 177, 177' on the
measured
well and corresponding points on the target well 175, and TFT l and TFT2
represent the
tool face to target values at the first and second survey points 177, 177',
respectively. As
described in greater detail below, Ox and 6y may be determined, for example,
from
azimuth and inclination measurements of the measured and target wells.
[0049] Distances dl and d2 may alternatively be expressed mathematically as
follows:
d 1= - ~x - °y tan(TFT2)
cos(TFTl)[tan(TFT2) - tan(TFTl)]
d 2 = - ~ - ~y t~(TFT 1) Equation 6
cos(TFT 2)[tan(TFT 2) - tan(TFT1)]
[0050] where dl, d2, fix, TFT1; and TFT2 are defined above.
9
CA 02460788 2004-03-12
23
[0051] As shown below in more detail, ~x and Dy may be determined from azimuth
and inclination values, respectively, of the measured and target wells: For
some drilling
applications in which embodiments of this invention are suitable, magnetic
interference
tends to interfere with the determination of azimuth values of the measured
well using
conventional magnetic surveying techniques. In such applications determination
of ~x
may be problematic. Thus, in certain applications, it may be advantageous to
determine
the distances dl and d2 independent from Ox (and therefore independent of the
azimuth
values of the measured and target wells).
[0052] In various applications, such as common well twinning and relief well
drilling
applications, the intent of the drilling operation is to position the measured
well
substantially parallel and side by side with the target well 175. As described
above, the
measured TFT values for such applications are approximately 90 or 270 degrees
(e.g.,
within about 45 degrees thereof). It will be appreciated that in such
applications relative
changes in the horizontal position between the measured and target wells, fix,
typically
has a minimal effect on the measured TFT values (i.e., results in a relatively
small ~TFT
value for a given fix). As such, for many applications, determination of the
distances dl
and d2 from survey points 177, 177' of the measured well to corresponding
points on the
target well 175 may be derived considering only relative changes in the
vertical position,
~y, between the measured and target wells.
[0053] With reference now to FIGURE 10A, distances dl and d2 may be expressed
mathematically with respect to ay, TFT1, and TFT2 as follows:
d 1= - DY tan(TFT 2)
cos(TFTl)[tan(TFT2) - tan(TFTI)]
CA 02460788 2004-03-12
24
d 2 = - ~Y ~(TFT l) Equation 7
cos(TFT2)[tan(TFT2) - tan(TFTl)]
[0054] where, as described above, dl and d2 represent the distances from the
measured
well to the target well at the first and second survey points 177, 177',
respectively, TFT1
and TFT2 represent the tool face to target values at the first and second
survey points 177,
177', respectively, and ~y represents the relative change in vertical position
between the
first and second survey points 177, 177' of the measured well and
corresponding points
on the target well.
[0055] Turning now to FIGURE IOB, for certain applications (e.g., when a
measured
well is drilled substantially side by side with a target well), the tool face
to target value
may be assumed to be approximately equal to 90 or 270 degrees. Based on such
an
assumption, the distances dl and d2 may alternatively be expressed
mathematically as
follows:
d l = ~Y
tan(aTFT)
d 2 = ~Y Equation 8
sin(OTFT)
[0056] where, as stated above, OTFT is the difference between the tool face to
target
values at the first and second survey points 177, 177'. A,t relatively small
~TFT values
(e.g., when OTFT is less than about 30 degrees), the distances dl and d2 may
alternatively be expressed mathematically as follows:
d 1= d 2 = ~Y Equation 9
~TFT
(0057] where OTFT is in units of radians.
CA 02460788 2004-03-12
[0058] Equation 9 advantageously describes distance (dl and d2) from the
measured
well to the target well 175 as being substantially proportional to Dy and as
substantially
inversely proportional to the change in tool face to target value aTFT. While
not
generally applicable to all well drilling applications (or even to all
twinning applications),
Equation 9 may be valuable for many applications in that it provides
relatively simple
operational guidance regarding the distance from the measured well to the
target well.
For example, in certain applications, if the change in tool face to target
value ~TFT
between two survey points is relatively small (e.g., less than about 5 degrees
or 0.1
radians) then the distance to the taxget well is at least an order of
magnitude greater than
Dy (e.g., dl arid d2 are about a factor of 10 greater than Dy when ~TFT is
about 5 degrees
or 0.1 radians). Conversely, if OTFT is relatively large (e.g., about 30
degrees or 0.5
radians) then the distance to the target well is only marginally greater than
~y (e.g., dl
and d2 are about a factor of 2 greater than 4y when OTFT is about 30 degrees
ar 0.5
radians).
[0059] With continued reference to FIGURES 1OA and 10B, and Equations 7
through
9, it can be seen that the distances from the first and second survey points
177, 177' of the
measured well to corresponding points on the target well are expressed
mathematically as
functions of ~y, TFT1 and TFT2. As described above, TFTl and TFT2 may be
determined from magnetic interference emanating from the target well: Dy may
typically
be determined from conventional survey .data obtained for the measured well
and/or from
historical survey data for the target well. In one exernplan,~ embodiment of
this invention,
~y may be determined from inclination values at the first and second survey
points 177,
177' of the measured well and corresponding points on the target well. The
inclination
values for the measured well may be determined via substantially any known
method,
3
CA 02460788 2004-03-12
26
such as, for example, via local gravity measurements, as described in more
detail below
and in the McElhinney patents. The inclination values of the target well are
typically
known from a historical survey obtained, for example, via gyroscope or other
conventional surveying methodologies in combination with known interpolation
techniques as required. Such inclination values may be utilized in
conjunction. with
substantially any known approach, such as minimum curvature, radius of
curvature,
average angle, and balanced tangential techniques, to determine the relative
change in
vertical position between the two wells, 0y. Using one such technique, ~y may
be
expressed mathematically as follows:
O = ~MD sin IncMl + IncM2 _ IncTl + IhcT2
.Y ( ( 2 2 )) Equation 10
[0060] where OMD represents the change in measured depth between the first and
second survey points, IncMl and IncM2 represent inclination values for the
measured
well at the first and second survey points 177, 177', and IncTl and IncT2
represent
inclination values for the target well at corresponding first and second
points.
[0061] As described above, for many drilling applications in which embodiments
of
this invention are suitable, magnetic interference from the target well tends
to
significantly interfere with the determination of the azimuth of the measured
well using
conventional magnetic surveying techniques. Further, such drilling
applications are often
carried out in near horizontal wells (e.g., to divert around a portion of a
pre-existing
borehole that has collapsed). Thus conventional gyroscope and gravity azimuth
surveying methods may be less than optimal for borehole surveying in such
applications.
As shown above, in Equations 7 through 10, the distances dl and d2 from the
measured
well to the target well may be determined from TFTI, TFT2, and the inclination
values at
CA 02460788 2004-03-12
27
corresponding points along the measured and target wells. It will be
appreciated that
Equations 7 through 10 are advantageously independent of the azimuth values of
either
the measured or target wells. Thus a determination of the azimuth values (or
the relative
change in azimuth values) is not necessary in the determination of distances
dl and d2.
Further, as described in more detail below, the distances dl and d2, along
with a historical
survey of the target well, may be utilized to determine the coordinates of the
first and
second survey points 177, 177' and the local azimuth of the measured well.
[0062] It will be appreciated that according to Equations 4 through 9,
determination of
the distances dl and d2 requires a relative change in the position of the
measured well
with respect to the target well (e.g., ~x and/or ~y) that results in a
measurable change in
the tool face to target angle (4TFT) between the first and second survey
points 177, 177'.
For certain applications in which the measured well closely parallels the
target v~ell it
may be desirable to occasionally deviate the path of the measured well with
respect to the
target well in order to achieve significant changes in tool face to target
angles (e.g., OTFT
on the order of a few degrees or more). Such occasional deviation of the path
of the
measured well may advantageously improve the accuracy of a distance
determination
between the two wells. For example, in an application in which the measured
well is
essentially parallel with the target well at a tool face to target angle of
about 90 degrees
(i.e., the measured well lies to the right of the target well), it may be
desirable to
occasionally deviate the measured well path upwards and then back downwards
with
respect to the target well. Such upward and downward deviation of the measured
well
path may result in measurable ~y and OTFT values that may be advantageously
utilized
to calculate distance values as described above.
CA 02460788 2004-03-12
28
[0063] The artisan of ordinary skill will readily recognize that Equations 4
through 10
may be written in numerous equivalent or similar forms. For example, the
definitions of
TFT 1 and TFT2 or the signs of 0x and ~y may be modified depending the
quadrant in
which survey points 177 and 177' reside. In addition, the origin in FIGURES 9
through
l0B may be located at one of survey points 177 or 177' rather than at the
target well 175.
All such modifications will be understood to be within the scope of this
invention.
[0064] With the determination of the direction (i.e., TFT or ~TFT) and the
distance, dl
or d2, from the measured borehole to the target borehole at various points
along the
measured borehole it is possible to determine the location (i.e., the absolute
coordinates)
of those points on the measured borehole based on historical survey data for
the target
well. The location at survey points 177 and 177' may be given as follows:
PMxl = PTx - d 1 sin(TFT l)
PMyl = PTy - dl cos(TF7'1)
PMx2 = PTy - d 2 sin(TFT 2) Equation 11
PlLIy2 = PTy - d2 cos(TFT2)
[0065] where PMxI and PMyI, represent x and y coordinates at survey point 177,
PMx2 and PMy2 represent x and y coordinates at survey point 177', PTx and PTy
represent x and y coordinates of the target well 175, dl and d2 represent
distances from
survey points 177, 177' to the target well 175, and TFTI and TFT2 represent
tool face to
target values between the survey points 177 and 177' and the target well 175.
It will be
appreciated that the coordinates determined in Equation 11 are in a coordinate
system
looking down the longitudinal axis of the target well. The artisan of ordinary
skill will
readily be able to convert such coordinates into one or more conventional
coordinate
systems, including, for example, true north, magnetic north, UTM, and other
custom
coordinates systems.
CA 02460788 2004-03-12
29
[0066] Once the coordinates have been determined at the survey points 177 and
177' in
a conventional coordinates system, deterniination of azimuth values for the
measured
borehole may be derived as follows:
AzM=arctan(Cy2-Cyl) Equation 12
Cx2 - Cxl
where AzM represents a local azimuth between survey points 177 and 177' and
Cxl, Cx2, Cyl, and Cy2 represent x and y coordinates in a conventional
coordinates
system at survey points 177 and 177', respectively. Inclination values may be
determined, for example, from conventional surveying methodologies, such as
via gravity
sensor measurements (as described in more detail below).
[0067] It can be seen that embodiments of this invention include a method for
drilling a
relief well (or a method for twinning a well) that includes utilizing the
surveying
techniques described herein to guide the drill string (the measured well)
along a
predetermined course substantially parallel with a target well. For example,
as described
above, an operator may utilize plots of tool face to target values versus well
depth to
adjust the vertical component of the drilling direction. Likewise a comparison
of the
azimuth values for the measured and target wells may be utilized to adjust the
azimuthal
(lateral) component of the drilling direction. Such a procedure enables the
position of a
measured well to be determined relative to the target well in substantially
real time,
thereby enabling the drilling direction to be adjusted to more closely
parallel the target
well.
[0068] In determining the magnetic interference vectors, tool face to target
values, the
distance between the measured and target wells, and the azimuth of the
measured well, it
may be advantageous in certain applications to employ one or more techniques
to
CA 02460788 2004-03-12
minimize or eliminate the effect of erroneous data. Several options are
available. For
example, it may be advantageous to apply statistical methods to eliminate
outlying points,
for example, removing points that are greater than some predetermined
deviation away
from a previously measured point. Thus for example, if the distance between
two wells is
3 feet at a first survey point, a distance of 23 feet may be rejected at a
second survey
point. In certain instances it may also be desirable to remove individual
interference
vectors from the above analysis. For example, an interference vector may be
removed
when the magnitude of the interference magnetic field vector is less than some
minimum
threshold (e.g., 0.001 Gauss).
(0069] An alternative, and also optional, technique for minimizing error and
reducing
the effect of erroneous data is to make multiple magnetic field measurements
at each
survey station. For example, magnetic field measurements may be made at
multiple tool
face settings (e.g., at 0, 90, 180, and 270 degrees) at each survey station in
the measured
well bore. Such rotation of the tool face, while effecting the individual
magnetometer
readings (i.e.; Bx and By), does not effect the interference magnetic field,
the tool face to
target, the distance between the two wells, or the azimuth of the measured
well.
[0070] With reference again to FIGURE 9 and Equations 4 and S, it was shown
above
that the distances dl and d2 between the first and second survey points 177,
177' on the
measured well and corresponding points on the target well I7S may be expressed
mathematically as a function of the tool face to target values TFT l and TFT2
and the
relative changes in the horizontal dx and vertical dy positions between the
first and
second survey points 177, 177' on the measured well and corresponding points
on the
target well 17S. With reference again to FIGURES 1.0A and 10B and Equations 6
through 8, it was shown that for certain applications in which TFT1 and TFT2
are about
m ___ . _. ..._.. ___._...e ~".~.,.~ ..~.. ~.
CA 02460788 2004-03-12
31
90 or 270 degrees (e.g., within about 45 degrees thereof) distances dl and d2
may
alternatively be expressed mathematically as a function of ~y, TFT1, and TFT2
(i.e.,
substantially independent of fix). As described above, such an alternative
approach
advantageously enables dl and d2 to be determined based on the measured TFT
values
(TFT1 and TFT2) and inclination values for the measured and target wells
(i.e.,
independent of azimuth values which are sometimes unreliable in regions of
magnetic
interference). However, it should be noted that this alternative approach is
not
necessarily suitable for all drilling applications. Rather, for some
applications
determination of the distances dl and d2 may require knowledge of ~x as
described in
Equations 4 and 5 and shown in FIGURE 9.
(0071] As described above, both Ox and 8y may be determined from conventional
survey data obtained for the measured well and historical survey data for the
target well.
While Dy may be determined from inclination values, as shown in Equation 10,
~x may
be determined from azimuth values at the first and second survey points 177,
177' of the
measured well and corresponding points on the target well. The azimuth values
for the
measured well may be determined via substantially any known method, such as,
for
example, via gravity MWD measurements, as described in more detail below and
in the
McElhinney patents. Azimuth values of the target well are typically known fibm
a
historical survey obtained, for example, via gyroscope or other conventional
surveying
methodologies in combination with known interpolation techniques as required.
Such
azimuth values may be utilized in conjunction with substantially any known
approach,
such as minimum curvature, radius of curvature, average angle, and balanced
tangential
techniques, to determine the relative change in horizontal position between
the two wells,
fix. Using one such technique, ~x may be expressed mathematically as follows:
CA 02460788 2004-03-12
32
~=~(s~{~4ziM12AziM2-AziTl2AziT2)) Eq~honl3
[0072] where ~MD represents the change in measured depth between the first and
second survey points, AziMl and AziM2 represent azimuth values for the
measured well
at the first and second survey points 177, 177', and AziTl and AziT2 represent
azimuth
values for the target well at corresponding first and second points.
[0073] In certain of the above applications, the intent of the drilling
operation may be to
position the measured well substantially above or below the target well 175
(FIGURE 9)
or to pass over or under the target well 175. As described above, the measured
TFT
values for such applications are approximately 0 or 180 degrees (e.g., within
about 45
degrees thereof]. It will be appreciated that in such applications relative
changes in the
vertical position, ~y, between the measured and target wells typically has a
minimal
effect on the measured TFT values (i.e., results in a relatively small ~TFT
value for a
given t1y). As such, for these applications, determination of the distances dl
and d2 from
survey points 177, 177' of the measured well to corresponding points on the
target well
175 may be derived considering only relative changes in the horizontal
position, fix,
between the measured and target wells.
[0074] With reference now to FIGURE lI, distances dl and d2 may be expressed
mathematically with respect to Ox, TFT1, and TFT2 as follows:
dl =
cos(TFTl)[tan(TFT2) - tan(TFTl)]
d2 =- -- ~ Equation 14
cos{TFT 2)[tan(TFT 2) - tan(TFT 1)]
(0075] As described above with respect to Equations 6 through 8, Equation 14
may be
expressed alternatively for applications in which the measured well is
substantially
.._....___._..~.~""~ ~p,._. ~~ .~. m_.,~,~"..-....~~, ~~.-M--- -».e~ ~,...
._~~_..._.__~.~___
CA 02460788 2004-03-12
33
parallel with and above or below the target well 175. In such instances, dl
and d2 may be
approximated as follows:
dl = d2 = ~ Equation 15
OTFT
[0076] where, as described above, ~x represents the relative change in
horizontal
position between first and second survey points 177, 177' of the measured well
and
corresponding points on the target well 175 and ~TFT represents the change in
TFT value
between the first and second survey points 177, 177'. Similar to Equation 9,
described
above, Equation 1 S advantageously describes the distance (dl and d2) from the
measured
well to the target well 175 as being substantially proportional to ax and as
substantially
inversely proportional to the change in tool face to target value aTFT. While,
not
generally applicable to all well drilling applications (or even to all
twinning applications),
Equation 15 may be valuable for certain exemplary applications in that it
provides
relatively simple operational guidance regarding the distance from the
measured well to
the target well.
(0077] The principles of exemplary embodiments of this invention
advantageously
provide for planning various well drilling applications, such as well twinning
and/or relief
well applications, in which a measured well passes within sensory range of
magnetic flux
of a target well. Such planning may, for example, advantageously provide
expected tool
face to target values (also referred to as bearing) and distances (also
referred to as range)
between the measured and target wells as a function of measured depth. With
reference
to FIGURE 12, one exemplary embodiment of a drilling plan 400 is shown for a
hypothetical well twinning operation. The display may include, for example,
conventional plan 403 and sectional405 views of the measured 277 and target
well 275.
CA 02460788 2004-03-12
34
The display may also include, for example, a traveling cylinder view 401
looking down
the target well, which is similar to that shown in FIGURES 7, 9, 10A, lOB, and
11, and
plots of the tool face to target values 407 and distances 409 from the
measured well to the
target well.
[0078] At the beginning of the hypothetical operation shown, the measured well
is
essentially parallel with and to the right of the target well (having a tool
face to target
angle of about 260 degrees and a distance to the target well of about ten feet
at a
measured depth of about 15900 feet). The intent of the drilling operation is
to remain
essentially parallel with the target well for several hundred feet before
crossing over and
descending down and to the left of the target well. In the exemplary plan
shown, the tool
face to target value remains essentially unchanged to a measured depth of
about 16200
feet. The measured well then builds slightly and crosses over the target well
as shown in
the traveling cylinder 401. At a measured depth of about 16600 feet the
drilling plan has
the measured well descending down and to the left away from the target well as
shown
making a closest approach to the target well at a range (distance) of about
three feet at a
bearing (TFT) of about 120 degrees. It will be appreciated that the drilling
plan and the
display shown in FIGURE 12 are merely exemplary and that numerous variations
thereof
are available within the full scope of the invention. Fox example, displays
including
inclination, azimuth, and relative changes in the horizontal and vertical
position of the
measured well relative to the target well may alternatively and/or
additionally be shown.
[0079] As described above, exemplary embodiments of this invention may be
utilized
in drilling twin wells for use in steam assisted gravity drainage
applications. In such
applications either the upper or lower well may be drilled first using
conventional
directional drilling techniques. In certain embodiments it may be advantageous
to drill
CA 02460788 2004-03-12
the larger diameter upper well first, since the casing string in the larger
well tends to
produce greater magnetic flux. However, the invention is not limited in this
regard, as
either the upper or the lower well may be drilled first. After drilling of the
first well is
complete, it may be cased (lined) using conventional casing joints. For steam
assisted
gravity drainage applications it is typically desirable to configure at least
the horizontal
section of the casing string such that it includes a plurality of opposing
magnetic poles,
for example as shown on FIGURES 4A through 4C. As described above, the use of
such
casing strings increases the magnetic flux density about the target well and
thus increases
the range of suitable use of the passive ranging techniques described herein
(e.g., up to
about 20 meters in some applications).
[0080] In typical steam assisted gravity drainage applications, the well
profile is often
J-shaped, having a relatively straight/vertical section (e.g., with an
inclination of about 30
degrees), followed by a build (e.g., at about 5 degrees per 100 feet) to an
essentially
straight/horizontal section (having an inclination of about 90 degrees) that
may extend up
to several thousand feet. After completion of the first well (e.g., drilling
and casing a J-
shaped upper well), a drilling plan for the lower well is typically refined
(e.g., as
described above with respect to FIGURE 12). The lower well may then be twinned
for
example, using conventional directional drilling techniques along with a
suitable
combination of the passive ranging techniques described herein.
[0081] In one useful twinning operation, the upper portion of the second well
(e.g., the
lower well) is twinned substantially parallel to and to the left of (or to the
right of) the
first well at a separation distance of about 2 meters. It will be appreciated
that the
invention is not limited in this regard: The TFT and distance between the two
wells may
be determined as described above with respect to Equations 3 through 10. In
such an
9
CA 02460788 2004-03-12
36
exemplary embodiment the direction of drilling is controlled to maintain a TFT
of about
90 degrees (e.g., as described above in more detail with respect to FIGURE 5)
and a
separation distance of about 2 meters. Surveys may be conducted at
substantially any
interval along the length of the well (e.g., 30 meters). Passive ranging and
Gravity MWD
techniques may also be utilized to determine azimuth values of the second well
as
described in more detail herein.
[0082] As the well builds towards horizontal, the second well may be gradually
moved
below the first well. This may be accomplished by steering the second well
with respect
to the first well such that the TFT changes from about 90 degrees to about 0
degrees. It
will be understood that gradually moving the first well above the second well
would
change the TFT from about 90 to about 180 degrees. Meanwhile the separation
distance
between the two wells may be gradually increased from about 2 meters to the
desired
separation distance (typically in the range of from about 4 to about 10 meters
depending
upon various reservoir characteristics). In this section of the well, the TFT
and distance
may also be determined and controlled as described above with respect to
Equations 3
through 10 and 13 through 15.
[0083] In typical steam assisted gravity drainage applications, it is
desirable to maintain
the lower well at a substantially fixed distance below the upper well in the
straight/horizontal section. The distance between the two wells may be
determined and
controlled as described above with respect to Equations 4 through 6 and 13
through 15.
In certain embodiments, (e.g., those in which the first well includes a
preconfigured
casing string as described above with respect to FIGURES 4 through 6) the
distance
between the two wells may also be determined via the magnetic field strength
measured
at points on the second well. For example, in such embodiments, the magnetic
properties
_ _~~.~. ~, ..~~~.. x.-~...~. ~.....__ ____.__-._~.
CA 02460788 2004-03-12
37
of each casing joint (e.g., magnetic pole location arid strength) may be
measured prior to
insertion in the casing string. The magnetic properties of each casing joint
may then be
included in a mathematical model of the casing string to determine theoretical
magnetic
properties of the casing string (e.g., as shown above in FIGURES SA through 6
which
were derived from a finite element model). Measurements of both the direction
and
strength of the magnetic field in the second well may then be compared to the
theoretical
magnetic field about the first well in order to determine a separation
distance
therebetween. For example, as shown in FIGURES SA through 6, a measured
magnetic
field strength of about 0.008 Gauss at a measured depth of about 2175 meters
would
indicate a separation distance between the two wells of about 6 meters.
[0084] In certain applications it may be advantageous to survey the second
well at
positions that are substantially longitudinally aligned with the opposing
poles in the
casing string of the first well (i.e., at substantially the maximum magnetic
field values).
The measured depths of such opposing poles are typically known to a close
approximation based on the characteristics of the preconfigured casing string.
Thus,
positioning the drill bit (or a particular MWD survey tool such as sensor set
120 shown on
FIGURE 1) in close proximity to a particular opposing pole may be
straightforward for
certain applications. Furthermore, the longitudinal position of the sensor
sets relative to
the opposing poles on the target well may be determined via measuring the
component of
the magnetic flux density parallel to the longitudinal axis of the second well
(the z
direction as shown on FIGURE 2). It will be appreciated that the longitudinal
component
of the magnetic flux density is substantially zero at the opposing poles and
increases to a
maximum between two adjacent opposing poles. In this manner any mismatch
between
the measured depths of the two wells may be accounted. In one advantageous
CA 02460788 2004-03-12
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embodiment, the longitudinal component of the magnetic :field may be
transmitted uphole
in substantially real time during drilling (e.g., via mud pulse telemetry).
Such dynamic
surveying enables the relative longitudinal and/or radial position between the
two wells to
be monitored in real time and thus may enable the sensor sets) to be more
accurately
positioned adjacent opposing poles on the target well.
[0085] In a typical steam assisted gravity drainage application, it is also
desirable that
the lower well resided substantially directly below the upper well (i.e., not
deviating more
than about 1-2 meters to the left or right of the upper well). As described
above, the tool
face to target angle (TFT) indicates the relative position of the second well
with respect to
the first well: At a TFT angle of 0 degrees, the second well resides directly
below the
first well. This orientation may be maintained by controlling the TFT angle
within
certain predetermined tolerances. Table 1 summarizes exemplary TFT tolerances
for
separation distances of 4, 6, 8, 10, and 12 meters and left right tolerances
of l, 2, and 3
meters, respectively. For example, to maintain a left right tolerance of ~ 1
meter at a
separation distance of 6 meters, requires that the TFT angle be controlled
within ~ 9
degrees. Likewise, to maintain a left right tolerance of f 2 meters at a
separation distance
of 6 meters requires that the T'FT angle be controlled within t 19 degrees.
TABLE 1
4 meters 6 meters 8 meters 10 meters 12 meters
+/-1 meterst 14 degrees~ 9 degrees~ 7 degrees~ 5 degreest 4 degrees
+/-2 meters~ 30 degrees+ 19 degrees~ 14 degrees~ 11 degreest 9 degrees
+/-3 meters~ 48 degrees+ 30 degrees~ 22 degrees+ 17 degrees~ 14 degrees
CA 02460788 2004-03-12
39
[0086] Embodiments of this invention may also be utilized in combination with
other
surveying techniques. For example, in applications in which the inclination of
the target
well is less than about 80 degrees, gravity azimuth methods (also referred to
as gravity
MWD), such as those described in the McElhinney patents, may be advantageously
used
to determine borehole azimuth values in the presence of magnetic interference.
Such
gravity MWD techniques are well suited for use with exemplary embodiments of
this
invention and may be advantageously utilized to determine ~x as described
above.
Alternatively andlor additionally, the magnetic field measurements may be
utilized to
determine magnetic azimuth values via known methods. Such magnetic azimuth
values
may be advantageously utilized at points along the measured well at which the
magnetic
interference is low, e.g., near a target well that has been sufficiently
demagnetized.
[0087] In a previous commonly-assigned application (U.S. Patent Application
Ser. No.
IO/369,353) the applicant discloses methods for determining azimuth via
gravity and
magnetic field measurements using, for example, MWD tools such as that
disclosed in
FIGURE 1. Refernng now to FIGURES 2 and 13 (FIGURE 13 is abstracted from U.S.
Patent Application Ser. No. 101369,353), the lower sensor set 120 has been
moved with
respect to upper sensor set 110 (by bending structure 140) resulting in a
change in
azimuth (denoted 'delta-azimuth' in FIGURE 13). The following equations show
how
the foregoing methodology nay be achieved. Note that this analysis assumes
that the
upper 110 and lower 120 sensor sets are rotationally fixed relative to one
another.
(0088] The borehole inclination (Incl and Inc2) may be described at the upper
110 and
lower 120 sensor sets, respectively, as follows:
Gxl2 + Gyl2
~ncl = arctan{ Gzl ) Equation 16
CA 02460788 2004-03-12
m
Inc2 = axctan( Gx22 + Gy22 ) Equation 17
Gz2
where G represents a gravity sensor measurement (such as, for example, a
gravity
vector measurement), x, y, and z refer to alignment along the x, y, and z
axes,
respectively, and 1 and 2 refer to the upper 110 and lower 120 sensor sets,
respectively.
Thus, for example, Gxl is a gravity sensor measurement aligned along the x-
axis taken
with the upper sensor set 110. The artisan of ordinary skill will readily
recognize that the
gravity measurements may be represented in unit vector form, and hence, Gxl,
Gyl, etc.,
represent directional components thereof.
[0089] The borehole azimuth at the lower sensor set 120 may be described as
follows:
BoreholeAzimuth= Ref'erenceAzimuth+DeltaAzimuth Equation 18
where the reference azimuth is the azimuth value at the upper sensor set 110
and
where:
DeltaAzimuth = Betca Equation 19
1- Sin((Incl + Inc2) l 2)
and:
{Gx2 * Gyl - Gy 2 * Gxl) * Gxl * Gyl * Gzl
Beta = arctan( ) Equation 20
Gz2*(Gxla+Gyl2)+Gzl*(Gx2*Gxl+Gy2*Gyl)
[0090) In other embodiments, Equation 19 may alternatively be expressed as
follows:
DeltaAzimuth = -Beta * Cl + Incl ~ Equation 19A
Inc2
[0091] Using the above relationships, a surveying methodology may be
established, in
which first and second gravity sensor sets (e.g., accelerometer sets) are
disposed, for
example, in a drill string. As noted above, surveying in this way is known to
be
serviceable and has been disclosed in U.S. Patent 6,480,119 (the '119 patent).
In order to
CA 02460788 2004-03-12
P
41
utilize this methodology, however, a directional tie-in, i.e., an azimuthal
reference, is
required at the start of a survey. The subsequent surveys are then chain
referenced to the
tie-in reference. For example, if a new survey point (also referred to herein
as a survey
station) has a delta azimuth of 2.51 degrees, it is conventionally added to
the previous
survey point (e.g., 183.40 degrees) to give a new azimuth (i.e., borehole
azimuth) of
185.91 degrees. A subsequent survey point having a delta azimuth of 1.17
degrees is
again added to the previous survey point giving a new azimuth of 187.08
degrees.
[0092] If a new survey point is not exactly the separation distance between
the two
sensor packages plus the depth of the previous survey point, the prior art
recognizes that
extrapolation or interpolation may be used to determine the reference azimuth.
However,
extrapolation and interpolation techniques risk the introduction of error to
the surveying
results. These errors may become significant when long reference chains are
required.
Thus it is generally preferred to survey at intervals equal to the separation
distance
between the sensor sets, which tends to increase the time and expense required
to perform
a reliable survey, especially when the separation distance is relatively small
(e.g., about
30 feet). It is therefore desirable to enhance the downhole surveying
technique described
above with supplemental referencing, thereby reducing (potentially eliminating
for some
applications) the need for tie-in referencing.
[0093] U.S. Patent Application 10/369,353 discloses method for utilizing
supplemental
reference data in borehole surveying applications. The supplemental reference
data may
be in substantially any suitable form, e.g., as provided by one or more
magnetometers
and/or gyroscopes. With continued reference to FIGURES 2 and 13, in one
embodiment,
the supplemental reference data are in the form of supplemental magnetometer
measurements obtained at the upper sensor set 110. The reference azimuth value
at the
i
CA 02460788 2004-03-12
42
upper sensor set 110, may be represented mathematically, utilizing the
supplemental
magnetometer data, as follows:
(Gxl * Byl - Gy1 * Bxl) * .~Gxla + Gyl2 + Gzl2
Referencel4zimuth = arctan(Bz1 * (Gxl2 + Gyla ) - Gzl * (Gxl * Bxl - Gyl *
Byl) ) Equation2l
where Bxl, Byl, and Bzl represent the measured magnetic field readings in the
x, y, and
z directions, respectively, at the upper sensor set 110 (e.g., via
magnetometer readings).
The borehole azimuth at the lower sensor set 120 may thus be represented as
follows:
(Gxl * Byl - Gyl * Bxl) * Gxl2 + Gyl2 + Gzl2
BoreholeAzimuth = arctan( ) + ...
Bzl*(Gxl2+Gyl2)-Gz1*(Gxl*Bxl-Gyl*Byl)
Beta Eq~,hon 22
1- Sin((Incl + Inc2) l 2)
where Beta is given by Equation 20 and Incl and Inc2 are given by Equations 16
and 17,
respectively, as described previously.
[0094] It will be appreciated that the above arrangement in which the upper
sensor set
110 (FIGURES 1 through 3B) includes a set of magnetometers is merely
exemplary.
Magnetometer sets may likewise be disposed at the lower sensor set 120. For
some
applications, as described in more detail below, it may be advantageous to
utilize
magnetometer measurements at both the upper 110 and lower 120 sensor sets.
Gyroscopes, or other direction sensing devices, may also be utilized to obtain
supplemental reference data at either the upper 110 or lower 120 sensor sets.
[0095] It will also be appreciated that the above discussion relates to the
generalized
case in which each sensor set provides three gravity vector measurements,
i.e., in the x, y,
and z directions. However, it will also be appreciated that it is possible to
take only two
CA 02460788 2004-03-12
43
gravity vector measurements, such as, for example, in the x and y directions
only, and to
solve for the third vector using existing knowledge of the total gravitational
field in the
area. Likewise, in the absence of magnetic interference, it is possible to
take only two
magnetic field measurements and to solve for the third using existing
knowledge of the
total magnetic field in the area.
[0096] While the passive ranging techniques described herein require only a
single
magnetometer set (e.g., located at the upper sensor set as ixi the above
example), it will be
appreciated that passive ranging may be further enhanced via the use of a
second set of
magnetometers (i.e., a first set of magnetometers at the upper sensor set and
a second set
of magnetometers at the lower sensor set). The use of two sets of
magnetometers, along
with the associated accelerometers, typically improves data density (i.e.,
more survey
points per unit length of the measured well), as shown in the examples
described above,
reduces the time required to gather passive ranging vector data, increases the
quality
assurance of the generated data, and builds in redundancy.
[0097] It will be understood that the aspects and features of the present
invention may
be embodied as logic that may be represented as instructions processed by, for
example, a
computer, a microprocessor, hardware, firmware, programmable circuitry, or any
other
processing device well known in the art. Similarly the logic may be embodied
on
software suitable to be executed by a processor, as is also well known in the
art. The
invention is not limited in this regard. The software, firmware, and/or
processing device
may be included, for example, on a down hole assembly in. the form of a
circuit board, on
board a sensor sub, or MWDfLWD sub. Alternatively the processing system may be
at
the surface and configured to process data sent to the surface by sensor sets
via a
telemetry or data link system also well known in the art. Electronic
information such as
CA 02460788 2004-03-12
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logic, software, or measured or processed data may be stored in memory
(volatile or non-
volatile), or on conventional electronic data storage devices such as are well
known in the
art.
[0098] The sensors and sensor sets referred to herein, such as accelerometers
and
magnetometers, are presently preferred to be chosen from among commercially
available
sensor devices that are well known in the art. Suitable accelerometer packages
for use in
service as disclosed herein include, for example, Part Number 979-0273-041
commercially available from Honeywell, and Part Number JA-SH175-1 commercially
available from Japan Aviation Electronics Industry, Ltd. (JAE). Suitable
magnetometer
packages are commercially available called out by name from MicroTesla, Ltd.,
or under
the brand name Tensor (TM) by Reuter Stokes, Inc. It will be understood that
the
foregoing commercial sensor packages are identified by way of example only,
and that
the invention is not limited to any particular deployment of commercially
available
sensors.
[0099] Although the present invention and its advantages have been described
in detail,
it should be understood that various changes, substitutions and alternations
can be made
herein without departing from the spirit and scope of the invention as defined
by the
appended claims.
