ROTATABLE SENSORS FOR MEASURING CHARACTERISTICS OF
SUBTERRANEAN FORMATION
Technical Field
[0001] The present disclosure relates generally to devices for use in a
wellbore in a subterranean formation and, more particularly to sensor assemblies
for measuring anisotropic characteristics of a subterranean formation.
Background
[0002] Various devices can be placed in a well traversing a hydrocarbon
bearing subterranean formation. Some devices can include sensors capable of
measuring attributes (e.g., resistivity) of the subterranean formation.
Measurements can be used to determine characteristics (e.g., composition) of
the subterranean formation. In some operations, the number of measurements
that can be obtained is limited. Greater numbers of measurements can provide
more detailed analysis, which can lead to greater efficiency or cost effective well
operations.
Brief Description of the Drawings
[0003] FIG. 1 is a diagram illustrating a drilling system, according to one
aspect of the present disclosure.
[0004] FIG. 2 is a diagram illustrating an example of a bottom hole sensor
assembly with rotatable antennas according to one aspect of the present
disclosure.
[0005] FIG. 3 is another diagram illustrating the bottom hole sensor
assembly of FIG. 2 according to one aspect of the present disclosure.
[0006] FIG. 4 is a diagram illustrating an example of a bottom hole sensor
assembly with an orientation sensor according to one aspect of the present
disclosure.
[0007] FIG. 5 is a diagram illustrating an example of a bottom hole sensor
assembly with multiple receive antennas according to one aspect of the present
disclosure.
[0008] FIG. 6 is a diagram illustrating an example of a bottom hole sensor
assembly with receive antennas oriented at different tilt angles according to one
aspect of the present disclosure.
[0009] FIG. 7 is a diagram illustrating an example of a rotatable sensor
assembly according to one aspect of the present disclosure.
[001 0] FIG. 8 is a diagram illustrating an example of a bottom hole sensor
assembly with two motors according to one aspect of the present disclosure.
[001 1] FIG. 9 is a diagram illustrating an example of a rotatable near-bit
sensor assembly according to one aspect of the present disclosure.
[001 2] FIG. 10 is a diagram illustrating an example of a bottom hole sensor
assembly with sensor assemblies, each having three formation sensors,
according to one aspect of the present disclosure.
[001 3] FIG. is a block diagram of a control system for a bottom hole
sensor assembly with rotatable sensors according to one aspect of the present
disclosure.
[0014] FIG. 12 is a block diagram of a control system for a rotatable sensor
assembly according to one aspect of the present disclosure.
[001 5] FIG. 13 is a flow chart illustrating an example method for measuring
anisotropic characteristics of a subterranean formation according to one aspect of
the present disclosure.
Detailed Description
[001 6] Certain aspects and examples of the present disclosure are directed
to sensor assemblies for measuring anisotropic, or directionally- dependent,
characteristics of a subterranean formation. Sensor assemblies can include
sensors deployed on a tool string. One or more of the sensors can be rotatable
relative to the tool string. Rotating one or more sensors relative to the tool string
can provide data about the subterranean formation at multiple zones around the
tool string.
[001 7] In one example, a rotatable antenna on a drill string may rotate
about the drill string for transmitting or receiving signals to determine resistivity at
various angles in the formation. The rotation of the rotatable antenna,
independent from any rotation of the drill string, can provide resistivity readings at
multiple angles regardless of whether the drill string is rotating for drilling. The
multiple directional resistivity readings can indicate boundaries of formation
layers near the drill string. A drill string operator may utilize the readings as
navigation aids in steering the direction of a new borehole being drilled for
optimal well bore placement with respect to the location of boundaries, faults,
calcite lens, or other natural or man-made subterranean structures.
[001 8] These illustrative examples are given to introduce the reader to the
general subject matter discussed here and are not intended to limit the scope of
the disclosed concepts. The following describes various additional aspects and
examples with reference to the drawings in which like numerals indicate like
elements, and directional descriptions are used to describe the illustrative
aspects. The following uses directional descriptions such as "above," "below,"
"upper," "lower," "left," "right," "downhole," etc. in relation to the illustrative aspects
as they are depicted in the figures, the downhole direction being toward the toe of
the well. Like the illustrative aspects, the numerals and directional descriptions
included in the following should not be used to limit the present disclosure.
Furthermore, the following uses the term "or" to denote any combination of
options separated by the term "or", including combinations in which only one of
the options is utilized and combinations in which more than one (and in some
cases, all) of the options are utilized.
[001 9] FIG. 1 schematically depicts an example of a well system 100
having a bottom hole sensor assembly 114. The well system 100 can include a
bore that is a wellbore 102 extending through various earth strata. The wellbore
102 can extend through a hydrocarbon bearing subterranean formation 110. A
casing string 104 can extend from the surface 106 to the subterranean formation
110. The casing string 104 can provide a conduit via which formation fluids, such
as production fluids produced from the subterranean formation 110, can travel
from the wellbore 102 to the surface 106.
[0020] A tool string 112 within the wellbore 102 can extend from the
surface into the subterranean formation 110. In some aspects, the tool string 112
can include a drill bit 116 introduced into the well system 100 for drilling the
wellbore 102 through the various earth strata. In other aspects, the tool string
112 can be introduced without the drill bit 116. As a non-limiting example of a
tool string 112 without a drill bit 116, the tool string 112 may be part of a wireline
tool utilized for downhole well operations. The tool string 112 can include a
bottom hole (or downhole) sensor assembly 114. Although FIG. 1 depicts the
bottom hole sensor assembly 114 in section of the wellbore 102 that is
substantially vertical, the bottom hole sensor assembly 114 can be located,
additionally or alternatively, in sections of the wellbore 102 that have other
orientations, including substantially horizontal. In some aspects, the bottom hole
sensor assembly 114 can be disposed in simpler wellbores, such as wellbores
102 without a casing string 104.
[0021] In some aspects, the tool string 112 can include a bent housing 118.
Examples of the bent housing 118 include a fixed bent housing or an adjustable
bent housing. The bent housing 118 can provide steering for the drill bit 116.
The bent housing 118 can allow drilling to proceed ahead in a certain direction in
response to the tool string 112 rotating. Ceasing rotation of the tool string 112
can allow the bent housing 118 to change the drilling direction of the tool string
112. A motor 120 can rotate the drill bit 116 while the tool string 112 slides
ahead through the formation 110 without the tool string 112 and bent housing 118
rotating. The tool string 112 can slide in the direction at which the bent housing
118 is facing, often called the tool face, as the motor 120 rotates the drill bit 116
on the bottom of the hole without the tool string 212 and bent housing 118
rotating. Sliding the tool string 112 can allow course adjustments in a drilling
path. Resuming rotation of the tool string 212 can cause the tool string 212 to
cease course adjustment and continue moving in the adjusted direction.
[0022] Different types of bottom hole sensor assemblies 114 can be used
in the well system 100 depicted in FIG. 1. For example, FIG. 2 is a crosssectional
side view of an example of a bottom hole sensor assembly 214 with
rotatable antennas 216, 218 according to one aspect. The bottom hole sensor
assembly 214 can include a tool string 212, a rotatable transmit antenna 216, a
rotatable receive antenna 218, a motor 222, a first angular position sensor 224,
and a second angular position sensor 225.
[0023] The rotatable transmit antenna 216 or the rotatable receive antenna
218 can be rotatively coupled with the tool string 212. The rotatable transmit
antenna 216 or the rotatable receive antenna 218 can rotate relative to the tool
string 212. The rotatable transmit antenna 216 and the rotatable receive antenna
218 can together measure a characteristic within a region of the formation 210.
The rotatable transmit antenna 216 can emit signals into the formation 210. The
rotatable receive antenna 218 can detect responses in the formation 210 to the
emitted signals. A sensitive volume 226 can define a region of the formation 210
in which the rotatable receive antenna 218 can detect a relatively largest portion
of the responses to the signals emitted by the rotatable transmit antenna 216.
[0024] The rotatable transmit antenna 216 and the rotatable receive
antenna 218 can be induction-type antennas. The direction of the signals emitted
into or received from the formation 210 by an induction-type antenna can depend
on an orientation of an equivalent dipole of the induction-type antenna. A tilt
angle can represent the deviation of the dipole orientation from an axial direction
of the tool string 212. The tilt angles of a pair of induction-type antennas can
affect the position of a sensitive volume measured by the pair of induction-type
antennas. For example, the position of the sensitive volume 226 relative to the
tool string 212 can depend on the tilt angle of the rotatable transmit antenna 216
and the tilt angle of the rotatable receive antenna 218, as depicted in FIG. 2 .
[0025] Examples of induction-type antenna include a solenoid, a
magnetometer, and a coil. A tilt angle of a solenoid antenna can be produced by
adjusting an elevation angle of a ferromagnetic core in the solenoid. A tilt angle
of a magnetometer antenna can be produced according to the orientation at
which the magnetometer antenna is mounted onto or into the bottom hole sensor
assembly 214. A tilt angle of a coil antenna can be produced by winding the coil
at an angle relative to the axial direction of the tool string 212. For example, the
rotatable transmit antenna 216 can include a wire winding 215 arranged in a
plane of winding 217 that is oriented approximately perpendicular to an
equivalent dipole of the wire winding 215, as depicted in FIG. 2 . The rotatable
receive antenna 218 can include a wire winding 213 arranged in a plane of
winding 219 that is oriented approximately perpendicular to an equivalent dipole
of the wire winding 213, as depicted in FIG. 2 .
[0026] Various relative arrangements of transmit and receive antennas are
possible. Transmit and receive antennas can be perpendicular to each other,
such that the tilt angle of a transmit antenna and a receive antenna differ by
substantially 90 degrees. Transmit and receive antennas can be parallel to each
other, such that the tilt angle of a transmit antenna and a receive antenna are
substantially the same. It is also possible for the tilt angle of one of the transmit
antenna or the receive antenna to be substantially equal to zero,
[0027] Although the bottom hole sensor assembly 214 is described above
as including a rotatable transmit antenna 216 and a rotatable receive antenna
218, the bottom hole sensor assembly 214 can alternatively or additionally
include one or more other sensors rotatable relative to the tool string 212. In
some aspects, the sensor rotatable relative to the tool string 212 can be an
azimuthal sensor or a sensor that is directionally dependent. Non-limiting
examples of azimuthal sensors include the aforementioned antennas, as well as
resistivity sensors, gamma ray sensors, acoustic sensors, nuclear magnetic
resonance sensors, and density sensors. Notwithstanding the suitability of these
azimuthal sensors or other sensors, for the sake of simplicity and clarity, aspects
herein are primarily described with respect to antennas. Also, although many
aspects described herein include multiple sensors rotatable relative to the tool
string 212, in some aspects, only one azimuthal sensor is rotatable relative to the
tool string 212.
[0028] The motor 222 can be coupled with the rotatable transmit antenna
216 or the rotatable receive antenna 218. In one example, the rotatable transmit
antenna 216 and the rotatable receive antenna 218 can be coupled to a shaft 230
driven by the motor 222. The rotatable transmit antenna 216 or the rotatable
receive antenna 218 can rotate relative to the tool string 212 in response to the
motor 222 rotating. In some aspects, the motor 222 can be dedicated for rotating
the rotatable transmit antenna 216 or the rotatable receive antenna 218. In other
aspects, the motor 222 can also provide other functions. In one example, the
motor 222 can be coupled with a drill bit portion of a drill string and provide power
for rotating drill bits without rotating the remainder of the drill string.
[0029] The motor 222 can be any suitable form of torsion power unit.
Examples of torsion power units include a mud motor, a turbine motor, an electric
motor, a Tubodrill motor, a vane motor, an air-powered motor, and a fluidpowered
motor. In some aspects, a torsion power unit can be a hydraulic
powered motor powered by a hydraulic pump. The pump can be powered by any
suitable energy source. Examples of suitable energy sources for such a pump
include electric power conveyed via a pipe (such as wired pipe or a pipe in pipe
system such as is available under the trade name Reelwell™), electric power
from local power generation (such as from a turbine-powered generator or other
form of energy harvesting device downhole), or electric power from an energy
storage device (such as batteries, rechargeable batteries, capacitors, or super
capacitors).
[0030] In some aspects, the angular position sensors 224, 225 can be
positioned for rotating respectively with the rotatable transmit antenna 216 or the
rotatable receive antenna 218. In one example, the first angular position sensor
224 and the rotatable transmit antenna 216 can be located on a shared housing
that is rotatable relative to the tool string 212. The first angular position sensor
224 can detect an orientation of the rotatable transmit antenna 216. For
example, the first angular position sensor 224 may have a a known rotational
relationship with the rotatable transmit antenna 216 that allows the orientation of
the rotatable transmit antenna 216 to be determined based on a known rotational
location of the first angular position sensor 224. The second angular position
sensor 225 can detect an orientation of the rotatable receive antenna 218. The
orientation of the rotatable transmit antenna 216 or the rotatable receive antenna
218 (or both) can indicate the position of the sensitive volume 226 in the
formation 210 relative to the tool string 212 at a particular time.
[0031] In some aspects, the first angular position sensor 224 or the second
angular position sensor 225 can measure an orientation or angular position of an
antenna that is stationary relative to the tool string 212. The first angular position
sensor 224 or the second angular position sensor 225 can additionally or
alternatively measure a changing orientation of an antenna that is rotating relative
to the tool string 212. In one example, the first angular position sensor 224 can
measure an orientation when the rotatable transmit antenna 216 is rotating
relative to the tool string 212 in response to rotating the motor 222 and the
second angular position sensor 225 can measure an orientation of the rotatable
receive antenna 218 that is stationary relative to the tool string 212 and not
rotating with the motor 222.
[0032] The orientation detected by the angular position sensor 224 or 225
can indicate a radial direction of a reference point of an antenna relative to an
angular reference. The angular position sensors 224, 225 can use any suitable
angular reference for indicating the orientation of the rotatable transmit antenna
216 or the rotatable receive antenna 218. In some aspects, the angular
reference can be relative to gravity, a scribe line of the tool string 212, another
reference feature of the tool string 212, or a northing, such as a true north or a
magnetic north. In one example of an angular reference relative to gravity, the
first angular position sensor 224 can measure the orientation of the rotatable
transmit antenna 216 relative to a top side of an inclined borehole, which may
also be referred to as a high side of the borehole.
[0033] The angular position sensor 224 or 225 can include one or more
survey direction sensors. The angular position sensor 224 or 225 can use any
suitable type or combination of survey direction sensors. Examples of survey
direction sensors include accelerometers, magnetometers, and gyroscopes. In
one example, an angular position sensor 224 or 225 can include two
accelerometers orthogonally oriented along X-Y axes that are cross plane to the
longitudinal axis of the tool string 212. Each accelerometer can detect a fraction
of the earth's gravitational field according to the orientation of the accelerometer.
The values detected by the accelerometers can indicate the orientation of the
angular position sensor 224 or 225, such as a deviation from a reference
direction of up or down. In another example, an angular position sensor 224 or
225 can include two magnetometers orthogonally oriented on the X-Y axes. The
magnetometers can measure the Earth's magnetic field from different
orientations to determine the direction of magnetic north and the deviation of the
angular position sensor 224 or 225 therefrom. In a further example, the angular
position sensor 224 or 225 can include a gyroscope which measures the
deviation of the angular position sensor 224 or 225 from the spin axis of the earth
(e.g. true north) or a referenced direction. In some aspects, a combination of
survey direction sensors can be used together to aid in further resolving
horizontal and vertical planes relative to the borehole. In one example, either a
gyroscope or an X-Y magnetometer arrangement may be complemented with an
X-Y axis accelerometer arrangement. In some aspects, additional survey
direction sensors of the same or different type can be included to provide
additional orientation information. In one example, a sensor that measures along
the Z-axis (e.g., along the longitudinal axis of the tool string 212) may be included
to reduce errors in resolving the direction of the vertical or horizontal planes (or
both) relative to the down direction, such as in circumstances in which resolution
is poor on the X-axis, Y-axis, or both.
[0034] FIG. 3 is a cross-sectional side view of the bottom hole sensor
assembly 214 of FIG. 2 with rotated antennas 216, 218 according to one aspect.
Rotating the motor 222 (such as depicted by the counterclockwise arrow 228 in
FIG. 3) can cause the rotatable transmit antenna 216 or the rotatable receive
antenna 218 to rotate relative to the tool string 212. Rotating the rotatable
transmit antenna 216 or the rotatable receive antenna 218 can shift the position
of the sensitive volume 226 of the formation 210 measured by the rotatable
transmit antenna 216 and the rotatable receive antenna 218. For example, the
sensitive volume 226 can be rotated from a position in the formation 210 above
the tool string 212 (such as depicted in FIG. 2) to a position in the formation 210
below the tool string 212 (such as depicted in FIG. 3). The sensitive volume 226
can be moved without rotation of the tool string 212. Rotating the position of the
sensitive volume 226 without rotating the tool string 212 can provide more data
about the formation 210 than would otherwise be provided without rotating the
tool string 212. In one example, resistivity information about the formation 210
can be obtained at various points around the tool string 212 while the tool string
212 is sliding for course adjustment. The resistivity information can be presented
to an operator of the tool string 212 for indicating a proximity to a boundary
between water-bearing earth strata and hydrocarbon-bearing earth strata.
[0035] In another example, rotating the position of the sensitive volume
226 without rotating the tool string 212 can provide data about the direction and
distance to a subterranean man-made object such as another well, another
borehole, or a lost drill string. For example, by detecting variations in the
surrounding volume (such as resistivity changes), the location of a man-made
object (such as an electrically conductive casing that has a lower resistivity than
the surrounding formation) may be determined.
[0036] In some aspects, the rotatable transmit antenna 216 or the rotatable
receive antenna 218 can be selectively rotatively coupled with the tool string 212.
In one example, the rotatable transmit antenna 216 can be locked to the tool
string 212 to prevent rotation of the rotatable transmit antenna 216 relative to the
tool string 212. In some aspects, the rotatable transmit antenna 216 or the
rotatable receive antenna 218 can rotate relative to the tool string 212 in a
direction opposite to a direction in which the tool string 212 rotates during drilling.
An opposite direction of rotation can allow a rate of rotation of the rotatable
antenna 216, 218 relative to the formation 210 to be less than a rate of rotation of
the tool string 212 relative to the formation 210.
[0037] Although the bottom hole sensor assembly 214 is depicted in FIGs.
2-3 with one rotatable transmit antenna 216 and one rotatable receive antenna
218 rotated by one motor 222, other arrangements are possible. For example, a
bottom hole sensor assembly may include a transmit antenna that is rotatable
and a receive antenna that is not rotatable or vice versa. A pair of antennas in
which only one of the antennas is rotatable may still provide a sensitive volume
that is rotatable relative to the tool string without rotating the tool string. The
bottom hole sensor assembly 214 can include multiple receive antennas, multiple
transmit antennas, multiple motors, multiple angular position sensors, or any
combination thereof.
[0038] Although the bottom hole sensor assembly 214 is depicted in FIGs.
2-3 with angular position sensors 224, 225 respectively positioned on shared
housings for rotating with the rotatable transmit antenna 216 and the rotatable
receive antenna 218, other arrangements are possible. For example, in some
aspects, the angular position sensor 224 or 225 associated with an antenna can
include a survey direction sensor that is not rotating at the same speed or
direction as the antenna. In at least such arrangements, the angular position
sensor may also include an orientation sensor that detects an orientation of the
antenna relative to the object containing the survey direction sensor. The
orientation sensor can detect an additional offset of the antenna from the
orientation measured by the survey direction sensor in order to determine the
orientation of the antenna relative to the angular reference. For example, FIG. 4
is a back cross-sectional view of an example of a bottom hole sensor assembly
314 with an orientation sensor 368 according to one aspect.
[0039] The bottom hole sensor assembly 314 can include a tool string 312,
a housing 356, and an angular position sensor 324. The housing 356 can be
rotatable relative to the tool string 312, such as depicted by the curved arrow 328
depicted in FIG. 4 . The tool string 212 can include a bore 301 . In some aspects,
the bore 301 provides a flow path for fluids, such as drilling fluids or production
fluids, to flow through the tool string 212. In additional or alternative aspects,
motors, shafts, gears, or other components for rotating the housing 356 relative
to the tool string 212 can be positioned within the bore 301 . (Some example
arrangements of such components are described below with respect to FIG. 7).
The housing 356 can carry an antenna 316. Rotating the housing 356 relative to
the tool string 312 can rotate the antenna 316 relative to the tool string 312. The
angular position sensor 324 can provide information about an orientation of the
antenna 316 relative to an angular reference that is separate from the tool string
312. Non-limiting examples of the angular reference include true north, magnetic
north, and a downward direction corresponding to a direction in which gravity of
the earth exerts the greatest pull.
[0040] The angular position sensor 324 can include a survey direction
sensor 325. The survey direction sensor can be positioned on or in the tool string
312 rather than on the housing 356. The survey direction sensor can detect an
angular position of the tool string 312 relative to the angular reference that is
separate from the tool string 312. The angular position sensor 324 can also
include an orientation sensor 368. The orientation sensor 368 can detect an
angular position of the antenna 316 relative to the survey direction sensor 325.
The orientation of the antenna 316 relative to the angular reference can be
determined based on readings from the orientation sensor 368 and the survey
direction sensor 325. For example, the angular offset of the antenna 316 from
the survey direction sensor 325 (measured by the orientation sensor 368) can be
combined with the angular offset of the survey direction sensor 325 from the
angular reference (measured by the survey direction sensor 325) to yield a total
angular offset of the antenna 316 from the angular reference. As an illustrative
example, the survey direction sensor 325 may be a gyroscope that detects
deviation of the tool string 312 from true north 399. The survey direction sensor
325 may detect that the tool string 312 is oriented at a 30-degree eastward
deviation 397 from true north 399. The orientation sensor 368 may detect that
the antenna 316 is oriented at a 60-degree eastward deviation 395 from the
location of the survey direction sensor 325 on the tool string 312. The combined
readings in such a scenario would indicate that the antenna 316 is oriented at a
total eastward deviation 393 of 90 degrees from true north 399.
[0041] In some aspects, the orientation sensor 368 can include magnets
335, 345. The magnets 335, 345 can be arranged at regular intervals around the
circumference of the tool string 212. The magnets 335, 345 can be arranged with
dipoles aligned in a radial direction of the tool string 212 on the X-Y plane. A
zero-point magnet 345 can have an inverted orientation relative to the remaining
magnets 335. For example, the zero-point magnet 345 can be arranged with a
South-North orientation in a radially inward direction if the remaining magnets
335 are arranged with a North-South orientation in a radially inward direction.
The zero-point magnet 345 can be aligned with (or at a known offset from) the
survey direction sensor 325. For example, the zero-point magnet 345 can be
aligned with or at a known offset from a scribe line 327 of the tool string 312. The
scribe line 327 may identify a reference orientation position of the survey
direction sensor 325 relative to the tool string 312. For example, a zero point of
the survey direction sensor 325 can be at a known fixed offset from the scribe
line 327. In some aspects, the known fixed offset from the scribe line 327 can be
measured after the bottom hole sensor assembly 314 is fully assembled.
[0042] The orientation sensor 368 can also include one or more
magnetometers 365 (such as a hall effect sensor). The magnetometer 365 can
detect variations in magnetic field strength as the magnetometer 365 moves
between adjacent magnets 335, 345. For example, the magnetometer 365 may
detect spikes in magnetic field magnitude each time the magnetometer 365 is
aligned with a magnet 335, 345. The inverted alignment of the zero-point magnet
345 can cause a spike in the opposite direction from the remaining magnets 335.
The number of spikes since the opposite spike of the zero-point magnet 345 can
provide a general indication of how far the magnetometer 365 has travelled past
the zero-point magnet 345. The difference in magnitude from the most recent
spike can indicate how far the magnetometer 365 has traveled from that spike
and provide more precise location information when the magnetometer 365 is
between magnets 335, 345. In some aspects, a gyroscope or interval timer can
be used with the magnetometer 365 to provide additional approximation of
intermediate positions between magnets 335, 345 based on sensed rotation
speed versus time.
[0043] Although the orientation sensor 368 is depicted in FIG. 4 with the
magnets 335, 345 carried by the tool string 312 and the magnetometers 365
carried by the housing 356, other arrangements are possible. In some aspects,
the magnetometers 365 are carried by the tool string 312 and the magnets 335,
345 are carried by the housing 356. In some aspects, a combination of magnets
335, 345 and magnetometers 365 can be located on a combination of the tool
string 312 and a motor shaft coupled with the housing 356 to rotate the housing
356 relative to the tool string 312. The motor shaft can be located in the bore 301
and coupled to the housing 356 in any suitable manner, including the example
arrangement described below with respect to FIG. 7 . An arrangement in which
an orientation sensor 368 monitors rotation of the motor shaft can provide an
alternate or additional indication of the angular position of the antenna based on
a known relationship between rotation of the motor shaft and rotation of the
housing.
[0044] In some aspects, including an orientation sensor 368 can reduce a
cost of producing the bottom hole sensor assembly 314 by reducing a number of
survey direction sensors 325 used in the bottom hole sensor assembly 314. In
some aspects, positioning one or more survey direction sensors 325 to rotate
with each rotating antenna 316 can reduce a complexity or increase an accuracy
of the bottom hole sensor assembly 314. For example, a survey direction sensor
325 that rotates with an antenna 316 may directly provide information about the
orientation of the antenna 316 relative to an angular reference. Directly obtaining
orientation information may reduce or eliminate inaccuracies from changes in
alignment amongst components arranged between the survey direction sensor
325 and the antenna 316, such as may occur as a result of drill string twist,
threaded connection over-tightening during drilling, motor drive train twist, gear
play variations, or other misalignment factors.
[0045] FIG. 5 is a cross-sectional side view of an example of a bottom hole
sensor assembly 414 with multiple receive antennas 418, 420 according to one
aspect of the present disclosure. The bottom hole sensor assembly 414 can
include a tool string 412, a rotatable transmit antenna 416, a first rotatable
receive antenna 418, a second rotatable receive antenna 420, and a motor 422.
[0046] The first rotatable receive antenna 418 and the second rotatable
receive antenna 420 can be located along the tool string 412 at different lengths
from the rotatable transmit antenna 416. The different lengths can cause the first
rotatable receive antenna 418 and the second rotatable receive antenna 420 to
align differently with the rotatable transmit antenna 416. The difference in
alignment can allow the rotatable transmit antenna 416 to produce a first
sensitive volume 426 in the formation 410 with the first rotatable receive antenna
418 and a second sensitive volume 428 with the second rotatable receive
antenna 420. The first sensitive volume 426 can be positioned at a different
depth of investigation than a depth of investigation of the second sensitive
volume 428.
[0047] In some aspects, the bottom hole sensor assembly 414 can provide
different depths of investigation simultaneously. For example, the rotatable
transmit antenna 416 may emit multiple frequencies for obtaining multiple depths
of investigation concurrently. In some aspects, the bottom hole sensor assembly
414 can provide different depths of investigation successively. For example, the
bottom hole sensor assembly 414 may consistently broadcast a frequency via the
rotatable transmit antenna 416. The bottom hole sensor assembly 414 may
obtain a first depth of investigation by activating the first rotatable receive
antenna 418 without activating the second rotatable receive antenna 420. The
bottom hole sensor assembly 414 may obtain a second depth of investigation by
deactivating the first rotatable receive antenna 418 and activating the second
rotatable receive antenna 420.
[0048] The rotatable transmit antenna 416, the first rotatable receive
antenna 418, and the second rotatable receive antenna 420 can rotate relative to
the tool string 412 in response to rotation of the motor 422. Rotating the first
sensitive volume 426 and the second sensitive volume 428 relative to the tool
string 412 can provide more diverse depths of investigation, improved vertical
resolution of data, compensation for variations in data, or any combination
thereof.
[0049] FIG. 6 is a cross-sectional side view of an example of a bottom hole
sensor assembly 514 with receive antennas 518, 520 oriented at different tilt
angles according to one aspect. The bottom hole sensor assembly 514 can
include a rotatable transmit antenna 516, a first rotatable receive antenna 518,
and a second rotatable receive antenna 520 positioned along a tool string 512.
[0050] The tool string 512 can have a downhole end 546. In some aspects,
a drill bit can be positioned at the downhole end 546. The tool string 512 can
travel in a direction through the formation 510. For example, the tool string 512
may travel in a substantially horizontal direction, as depicted by the rightward
arrow in FIG. 6 .
[0051] The first rotatable receive antenna 518 can be oriented with a plane
of winding 519 positioned at a tilt angle that is substantially perpendicular to a tilt
angle of a plane of winding 517 of the rotatable transmit antenna 516. The
perpendicular orientation can produce a first sensitive volume 526 positioned
between the rotatable transmit antenna 516 and the first rotatable receive
antenna 518. The first sensitive volume 526 can provide information about a
portion of the formation 510 that is positioned laterally to the tool string 512. For
example, the first sensitive volume 526 can be positioned below the horizontal
direction of travel of the tool string 512, as depicted in FIG. 6 .
[0052] The second rotatable receive antenna 520 can have a plane of
winding 521 oriented at a tilt angle that is substantially parallel to a tilt angle of
the plane of winding 517 of the rotatable transmit antenna 516. The parallel
orientation can produce a second sensitive volume 528 and a third sensitive
volume 529. The second sensitive volume 528 can include a portion 532 that
extends beyond the rotatable transmit antenna 516 and away from the second
rotatable receive antenna 520. For example, the second sensitive volume 528
can include a portion 532 that extends ahead (e.g., depicted toward the right in
FIG. 6) of the rotatable transmit antenna 516. In some aspects, the second
sensitive volume 528 from a parallel orientation can extend ahead of the
downhole end 546 of the tool string 512. In one example, a parallel orientation
can provide information about a region that is ahead of a drill bit in a drill string.
In some aspects, positioning an antenna closer to the downhole end 546 of the
tool string 512 can increase a distance ahead of the downhole end 546 that can
be detected. For example, the rotatable transmit antenna 516 can be positioned
downhole of a motor 522 that causes rotation of one or more antennas relative to
the tool string 512. The third sensitive volume 529 can include a portion 533 that
extends beyond the second rotatable receive antenna 520 and away from the
rotatable transmit antenna 516. For example, the third sensitive volume 529 can
include a portion 533 that extends behind (e.g., depicted toward the left in FIG. 6)
of the second rotatable receive antenna 520.
[0053] A perpendicular tilt angle orientation can provide a first sensitive
volume 526 that is smaller than a second sensitive volume 528 provided by a
parallel tilt angle orientation. The smaller size of the first sensitive volume 526
can provide readings with a higher resolution than readings provided by the
second sensitive volume 528. The larger size of the second sensitive volume
528 can provide readings that correspond to regions of the formation 510 that are
further away from the tool string 512 than readings provided by the first sensitive
volume 526. Combining the shallower readings of the first sensitive volume 526
and the deeper readings of the second sensitive volume 528 can provide a profile
of a characteristic of the formation 510 radially around the tool string 512. A
profile of a characteristic of the formation 510 can improve interpretation or
identification of boundaries of differing layers in the formation 510.
[0054] FIG. 7 is a cross-sectional side view of an example of a rotatable
sensor assembly 650 according to one aspect. The rotatable sensor assembly
650 can rotate a sensor relative to a tool string 612 such as the rotatable sensors
described above with respect to FIGs. 2-6. The rotatable sensor assembly 650
can include a body 652, a shaft 654, and a housing 656.
[0055] The body 652 can be part of a tool string 612. The body 652 may
include coupling features 658a, 658b for connection with other portions 660a,
660b of the tool string 612. For example, coupling features 658a, 658b can be
threaded surfaces.
[0056] The shaft 654 can be positioned within the body 652. The shaft 654
can be supported relative to the body 652 by bearing assemblies 662a, 662b.
Bearing assemblies 662a, 662b can allow shaft 654 to rotate relative to the body
652. In some aspects, the bearing assemblies 662a,662b can restrict passage of
fluid. In one example, the bearing assemblies 662a, 662b seal a chamber 664
around the shaft 654. In another example, the bearing assemblies 662a, 662b
allow some passage of fluid for lubrication of components within the chamber
664. In some aspects, the shaft 654 can include an internal passageway 666.
The passageway 666 can allow fluid to flow through the shaft 654 from one end
of the chamber 664 to the other. For example, the passageway 666 may provide
a path for drilling fluids to reach and provide power to a mud motor in a drilling
operation.
[0057] The shaft 654 can be coupled to a motor, such as a motor 222
described above with respect to FIG. 2 . In one example, the shaft 654 can be
connected to a mud motor via a continuous velocity joint 668. In another
example, the shaft 654 may be the rotor of the motor. The shaft 654 can rotate in
response to operation of the motor. The shaft 654 can communicate torsional
motion of the motor to other objects. In some aspects, the shaft 654 can be
linked with a coupling 670 to communicate torsional motion to an object located
in an axial direction from the shaft 654. In one example, the shaft 654 can be
linked by the coupling 670 to cause rotation of the shaft 654 of another rotatable
sensor assembly 650 for synchronized rotation of the rotatable sensor
assemblies.
[0058] The housing 656 can be torsionally coupled with the shaft 654 such
that rotation of the shaft 654 causes rotation of the housing 656. For example,
the shaft 654 can be torsionally coupled with the housing 656 via one or more
gears 670a, 670b. The housing 656 can include a gear surface 672 for engaging
the gears 670a, 670b. In one example, a gear 670a affixed to the shaft 654 can
engage a planetary gear 670b. The planetary gear 670b can be affixed to a
planetary shaft 674 that is supported by the body 652. Although only one
planetary gear 670b and one planetary shaft 674 is depicted in FIG. 7, multiple
planetary gears 670b and planetary shafts 674 can be positioned radially about
the shaft 654. The one or more planetary gears 670b can engage the gear
surface 672 on the housing 656 and the gear 670a affixed to the shaft 654 to
transfer rotational motion between the shaft 654 and the housing 656.
[0059] In some aspects, bearings 676 can be positioned between the
housing 656 and the body 652. The bearings 676 can be radial bearings, axial
bearings, or some combination thereof. A combination of axial and radial
bearings can allow the housing 656 to continue to rotate relative to the body 652
in the presence of external loads applied on the housing that might otherwise
impede rotation. In some aspects, springs 678 or other biasing alignment
devices can be positioned with the bearings 676 to maintain the bearings 676 in
position under applied external loads.
[0060] The housing 656 can include a formation sensor 680, a body
angular position sensor 682, a shaft angular position sensor 684, a survey
direction sensor 686, an electronics package 688, and a communications device
690. Although the housing 656 is depicted in FIG. 7 with all of these
components, in some aspects, one or more of these components can be omitted
from the housing 656.
[0061] The formation sensor 680 can detect characteristics of a formation
610. For example, the formation sensor 680 can be a rotatable transmit antenna
216 or a rotatable receive antenna 218 as described above with respect to FIG.
2 . In some aspects, the formation sensor 680 is a transceiver that can be
switched between a transmitting mode and a receiving mode. In some aspects,
the formation sensor 680 can be a directional sensor other than an antenna for
detecting resistance in the formation. Non-limiting examples of such an
alternative formation sensor 680 include a gamma ray sensor, an acoustic
sensor, a nuclear magnetic resonance sensor, and a density sensor. All such
sensors can be used additionally or alternatively for sensing characteristics of
the formation or the direction and distance to sensed man-made objects within
the formation, such as another well bore, well bore tubular or a lost in hole drill
string. Although the rotatable sensor assembly 650 is depicted in FIG. 7 with a
single formation sensor 680, other arrangements are possible. In some aspects,
the rotatable sensor assembly 650 can include multiple formation sensors 680 or
multiple distance and direction ranging sensors. These multiple formation
sensors 680 or distance and ranging sensors may be of the same or different
types from one another.
[0062] The body angular position sensor 682 can detect an angular
position of the formation sensor 680 relative to the body 652 of the rotatable
sensor assembly 650. For example, the body angular position sensor 682 may
optically detect markers 692 positioned around the circumference of the body
652. The marker 692 detected at a particular time can indicate the angular
position of the formation sensor 680 relative to the body 652 at the particular
time.
[0063] The shaft angular position sensor 684 can detect an angular
position of the formation sensor 680 relative to the shaft 654 of the rotatable
sensor assembly 650. For example, the shaft angular position sensor 684 may
detect a magnetic field of one or more magnets 694 coupled with the shaft 654 or
a planetary shaft 674 (shown on coupled with a planetary shaft 674 in FIG. 7).
The strength of the magnetic field detected at a particular time can indicate the
angular position of the formation sensor 680 relative to the shaft 654 at the
particular time.
[0064] The survey direction sensor 686 can detect an angular position of
the survey direction sensor 686 relative to an angular reference distinct from the
rotatable sensor assembly 650. For example, an angular position may be
detected based on gravity, true north, or magnetic north, such as by one or more
accelerometers, gyroscopes, or magnetometers. The strength or direction of
readings detected by one or more of these components at a particular time can
indicate an angular position or orientation of the survey direction sensor 686
relative to the angular reference.
[0065] Positioning the survey direction sensor 686 on the housing 656 with
the formation sensor 680 can cause the angular position detected by the survey
direction sensor 686 to directly correspond to the angular position of the
formation sensor 680. For example, the angular deflection of the formation
sensor 680 from the angular reference can be equal to the angular deflection
detected by the survey direction sensor 686 or offset by a known amount
corresponding to the manner in which the survey direction sensor 686 and the
formation sensor 680 are aligned relative to one another on the housing 656.
[0066] In some aspects, the survey direction sensor 686 can be located in
a location other than the housing 656, such as elsewhere in the tool string 612.
In at least such arrangements the body angular position sensor 682 or the shaft
angular position sensor 684 can determine the angular position of the formation
sensor 680 relative to the survey direction sensor 686, much as the orientation
sensor 368 (described above with respect to FIG. 4) can determine the angular
position of the antenna 316 relative to the survey direction sensor 325. This
angular position of the formation sensor 680 relative to the survey direction
sensor 686 can be combined with the angular position of the survey direction
sensor 686 to determine the orientation of the formation sensor 680 relative to
the angular reference, much as the orientation of the antenna 316 relative to the
angular reference can be determined based on readings from the orientation
sensor 368 and the survey direction sensor 325 (described above with respect to
FIG. 4).
[0067] The electronics package 688 can send or receive information to the
various data producing sensors described above (e.g., the body angular position
sensor 682, the shaft angular position sensor 684, the survey direction sensor
686, the formation sensor 680, or some combination thereof). The electronics
package 688 may also provide a centralized time keeping function for
synchronizing or synthesizing the timing of readings from the data producing
sensors. In some aspects, one or more of the data producing sensors are
integrated into the electronics package 688.
[0068] The electronics package 688 may include one or more components
of an information handling system. As used herein, the term "information
handling system" refers to a system including one or more processors coupled
with a non-transitory memory device. Non-limiting examples of the memory
device include RAM and ROM. The memory device can store machine-readable
instructions executable by the one or more processors. When executed by a
processor, the instructions can cause the processor to perform functions, which
can include various of the functions described herein. As an illustrative example,
an information handling system can be configured to perform functions described
with respect to the electronics package 688 in the preceding paragraph and
elsewhere herein. Furthermore, the term "information handling system" is not
limited solely to the electronics package 688 described with reference to FIG. 7 .
Further non-limiting examples of information handling systems include
microcontrollers, analog electronics, computing systems located at the surface,
and combinations thereof.
[0069] The electronics package 688 can also send or receive information
via the communications device 690. In one example, the communications device
690 can be a toroid for providing short hop communications over a wireless
network to other devices in the bottom hole assembly, such as the bottom hole
sensor assembly 214 or at any intermediate point in a drill string. Other
examples of communications device 690 include an inductive coupler or a slip
ring.
[0070] The electronics package 688, the data producing sensors, and the
communications device 690 (or any combination thereof) can be powered by any
suitable power source. In one example, the power source can be batteries
included in the electronics package 688 in the housing 656. In another example,
the power source can be located remotely from the housing 656 (such as
elsewhere in a bottom hole assembly) and transferred to the housing 656 by a
slip ring for communicating power from the body 652 to the housing 656.
[0071] FIG. 8 is a cross-sectional side view of an example of a bottom hole
sensor assembly 714 with two motors 722, 736 according to one aspect. The
bottom hole sensor assembly 714 can include a first motor 722, a second motor
736, a first rotatable sensor assembly 716, a second rotatable sensor assembly
718, a third rotatable sensor assembly 720, a rotatable near-bit sensor assembly
738, and a drill bit 746 positioned along a tool string 712. In some aspects, the
first rotatable sensor assembly 716, the second rotatable sensor assembly 718,
and the third rotatable sensor assembly 720 can each be similar to the rotatable
sensor assembly 650 described above with respect to FIG. 7 .
[0072] The first rotatable sensor assembly 716 can be coupled with the first
motor 722. The first motor 722 can cause the first rotatable sensor assembly 716
to rotate independently of the tool string 712 or the second motor 736. In one
example, the second motor 736 can rotate the drill bit 746. The first motor 722
can allow the first rotatable sensor assembly 716 to be rotated at a rate
independent from a rate of rotation of the drill bit 746. Independent rotation may
allow a sweep rate of the first rotatable sensor assembly 716 to be optimized,
such as based on a rate of penetration of a well being drilled.
[0073] The second motor 736 can be coupled with the second rotatable
sensor assembly 718, the third rotatable sensor assembly 720, the rotatable
near-bit sensor assembly 738, and the drill bit 746. Coupling multiple rotatable
sensor assemblies 718, 720, 738 with a common motor 736 can allow the
rotatable sensor assemblies 718, 720, 738 to rotate in synchronization.
Synchronized rotation can allow simplified configurations of the bottom hole
sensor assembly 714, such as configurations with reduced numbers of motors or
angular position sensors.
[0074] One or more of the rotatable sensor assemblies 716, 718, 720, or
738 can include multiple sensors 780a, 780b. The multiple sensors 780a, 780b
can be tilted relative to one another such that a different measurement can be
made with the first sensor 780a than with the second sensor 780b. In one
example, the multiple sensors 780a, 780b can be windings of an antenna
arranged in planes of winding that are tilted relative to each other. A
characteristic of a subterranean formation can be determined both at a first
position in the first winding plane and at a second position in the second winding
plane based on respective orientations of the receive antenna and the transmit
antenna. In some aspects, the multiple sensors 780a, 780b can be arranged
substantially perpendicular to each other.
[0075] Multiple sensors 780a, 780b in a rotatable sensor assembly 716,
718, 720, or 738 can provide a greater number of data points for calculating
formation characteristics. For example, crossed antennas can provide more
channels, i.e., measurements from a distinct transmitter and receiver
combination. Crossed antennas can also allow synthesizing measurements from
dipole angles that do not exist physically, such as by performing a weighted
average of the responses from each of the crossed antennas.
[0076] The rotatable near-bit sensor assembly 738 can be different from
the rotatable sensor assembly 650 described above with respect to FIG. 7 . For
example, FIG. 9 is a cross-sectional side view of an example of a rotatable nearbit
sensor assembly 838 according to one aspect. The rotatable near-bit sensor
assembly 838 can include a body 852, a shaft 854, and an electronics housing or
insert 856. In some aspects, the rotatable near-bit sensor assembly 838 can be
located near a downhole end of a tool string to provide a rotatable sensor for
looking ahead of the downhole end of a tool string or ahead of a drill bit in a drill
string.
[0077] The body 852 can be coupled with the shaft 854. The shaft 854 can
be rotatable by a motor. The shaft 854 can include a passageway 866 through
which drilling fluid can flow. The body 852 can have a hollow interior defining a
chamber 864. The body 852 can include coupling features 858 for connection
with other tools, such as a drill bit, other sensors, or a steering tool. In one
example, the coupling features 858 can be threaded surfaces. Drilling fluid
flowing through the shaft 854 can flow through the chamber 864 and through the
coupling features 858. The body 852 can include a formation sensor 880 and a
communications device 890.
[0078] The insert 856 can be installed into the chamber 864. The insert
can include a central bore 896. The bore 896 can provide a path for drilling fluid
to flow from the shaft 854 through the coupling features 858. The insert 856 can
include a sealed volume 898. The sealed volume 898 can contain an electronics
package 888. Installation of the insert 856 into the chamber 864 can establish
electronic communication between the electronics package 888 and the
formation sensor 880. Installation of the insert 856 into the chamber 864 can
establish electronic communication between the electronics package 888 and the
communications device 890. In some aspects, the electronics package 888 can
include one or more angular position sensors 886 for determining an angular
position of the formation sensor 880. The electronics package 888 can transmit
information from the formation sensor 880 via the communications device 890.
[0079] FIG. 10 is a cross-sectional side view of an example of a bottom
hole sensor assembly 914 with sensor assemblies 916, 918, 920, 938 each
having three formation sensors 980a, 980b, 980c according to one aspect.
Sensor assemblies 916, 918, 920, 938 can include any number of crossed
sensors 980a, 980b, 980c. Configurations with three crossed sensors 980a,
980b, 980c (such as depicted in FIG. 10) can provide more channels and data
points than configurations with fewer crossed sensors 780a, 780b (such as
depicted in FIG. 8). In some aspects, while a configuration of three crossed
sensors 980a, 980b, 980c in the absence of rotation can provide sufficient data
for precise measurements, rotating one or more of the sensor assemblies 916,
918, 920, 938 can provide additional data for reducing noise or otherwise
improving the quality of information obtained from the rotatable sensor
assemblies 916, 918, 920, 938.
[0080] In some aspects, fewer than all of the sensor assemblies 916, 918,
920, 938 are rotatable. For example, a motor 922 coupled with the sensor
assemblies 916, 938 can cause the sensor assemblies 916, 938 to rotate while
sensor assemblies 918, 920 remain stationary. Reducing the number of rotating
sensors can reduce the complexity of the bottom hole sensor assembly 914 by
reducing a number moving parts. In some aspects, the rotating sensor
assemblies 916, 938 transmit and the stationary sensor assemblies 918, 920
receive. In other aspects, the stationary sensor assemblies 918, 920 transmit
and the rotating sensor assemblies 916, 938 receive. The bottom hole sensor
assembly 914 can include any combination of stationary or rotating sensor
assemblies for transmitting and receiving. In some aspects, a rotatable sensor
assembly (such as sensor assemblies 916, 938 depicted in FIG. 10) can be
locked to the tool string 912 to stop or prevent rotation and temporarily convert
the rotatable sensor assembly to a stationary sensor assembly.
[0081] FIG. 11 is a block diagram of a control system 1000 for a bottom
hole sensor assembly with rotatable sensors according to one aspect. The
bottom hole sensor assembly can include a system control center 1002,
transmitters 1004a-n, receivers 1006a-m, a data acquisition unit 1008, a data
buffer 1010, a data processing unit 1012, and a communication unit 1014, a time
synchronizer 1020, and a motor controller 1022.
[0082] The system control center 1002 can form all or part of an information
handling system, which may include or interface with other information handling
systems described herein. For example, the system control center 1002 can
include one or more processors or analog electronics. The system control center
1002 can manage the operation of other components in the control system 1000.
A signal within a frequency in range 1 Hz to 10 MHz can be generated by the
system control center 1002 and fed to a number of transmitters 1004a-n (any
number "n" of transmitters 1004a-n can be included). In one example, the
transmitters 1004a-n can include transmit antennas that can emit electromagnetic
waves into the wellbore formation in response to currents passed through the
antennas. In some aspects, any of the transmitters 1004a-n can include multiple
transmit antennas connected to a single transmitter via a demultiplexer that is
controlled via the system control center 1002. This may reduce the total number
of transmitters 1004a-n, the size of electronics, and complexity of the control
system 1000.
[0083] Receivers 1006a-m (any number "m" of receivers 1006a-m can be
included) can receive an electromagnetic wave signal from the wellbore
formation. In one example, the receivers 1006a-m include antennas. The
received signal can be directed to the system control center 1002. Analogous to
the transmitters 1004a-n with multiple transmit antennas, multiple receive
antennas can be connected to the same receiver 1006a-m via a demultiplexer for
efficiency. Multiple frequencies may be transmitted and received at the same
time to increase functionality within a limited window of time. In one example,
square or other time waveforms can excite multiple frequencies simultaneously at
the transmitters 1004a-n. The frequencies can be separated by filters at the
receiving end in the data acquisition unit 1008. Signals from each transmitter
1004a-n can be received at all receivers 1006a-m and recorded. The time
synchronizer 1020 can include a clock or other device that can provide a
consistent time reference for tracking when the various signals are emitted and
received. The data buffer 1010 can store received signals for processing. The
data processing unit 1012 can perform processing or inversion on the data to
convert the signal information into data about characteristics of the wellbore
formation. The inversion may be performed downhole, or in a computer at the
surface 1016 after the data is transferred to the surface 1016. The
communication unit 1014 can communicate the data or results to the surface
1016, such as to a control system located at the surface 1016. In one example,
the data or results can be utilized to direct the direction of a drill string in a drilling
operation, such as by providing information to a drill string operator via a
visualization device at the surface or by providing information to an automated
drill string guidance system. The communication unit 1014 can additionally or
alternatively communicate the data or results to other tools downhole, e.g., to
improve various aspects of locating and extracting hydrocarbons. The
communication unit 1014 can include appropriate components or combinations
thereof for communicating by any suitable form of telemetry, including but not
limited to, any combination of electronic pulses, analog signals, amplitude
modulated patterns, frequency modulated patterns, or electromagnetic waves,
any of which may conveyed by any combination of wired, wireless, or mud-pulse
transmissions.
[0084] The motor controller 1022 can control one or more motors used for
rotating any of the transmitters 1004a-n or receivers 1006a-m. The motor
controller 1022 can form all or part of an information handling system, which may
include or interface with other information handling systems described herein.
The motor controller 1022 can adjust the rate of rotation of the transmitters
1004a-n or receivers 1006a-m by controlling the rate of rotation of the associated
motor(s). In some aspects, the motor controller 1022 can stop the rotation at a
particular point to orient one or more of the transmitters 1004a-n or receivers
1006a-m in a particular direction for measuring a particular region of interest in
the wellbore formation.
[0085] In some aspects, one or more of the transmitters 1004a-n or the
receivers 1006a-m can correspond to a rotatable sensor assembly 1028. For
example, a rotatable sensor assembly 1028 can be the rotatable sensor
assembly 650 as described with respect to FIG. 7 above. FIG. 12 is a block
diagram of a control system 1100 for a rotatable sensor assembly 1028
according to one aspect. The control system 1100 can form all or part of an
information handling system, which may include or interface with other
information handling systems described herein. The control system 1100 can
include a controller 1102, memory 1104, a survey direction sensor 1106, a
formation sensor 1108, a power source 1110, a shaft position sensor 1112, a
communications device 1114, a housing position sensor 1116, a time
synchronizer 1118, and a rate controller 1120. Although the control system 1100
for a rotatable sensor assembly 1028 is depicted in FIG. 12 with all of these listed
components, in some aspects, one or more of these components can be omitted
or incorporated directly as part of the control system 1000 depicted in FIG. 11.
[0086] The controller 1102 can form all or part of an information handling
system, which may include or interface with other information handling systems
described herein. For example, the controller 1102 can include a processor. The
memory 1104 can store machine-readable instructions accessible by the
controller 1102. The memory 1104 can store data retrievable after a well
operation is completed. Storing data in memory 1104 can reduce an amount of
data that is communicated to the surface during operation. The formation sensor
1108 can receive signals from the wellbore formation and provide related data to
the controller 1102. For example, the formation sensor 1108 can be the
formation sensor 680 described above with respect to FIG. 7 .
[0087] The power source 1110 can provide electric power for the various
electronics of the control system 1100. The power source 1110 can be any
suitable power source, including batteries, a slip ring or other connection to a wire
or other conduit to another power source at the surface or in the tool string, or a
generator driven by drilling fluids or the differential rotation between the bottom
hole assembly and the sensor housing (such as an alternator).
[0088] In some aspects, the memory 1104 can also store data to be
organized and analyzed. For example, as formation sensors 680 rotate, the
orientation of the azimuthal measurement can be binned in the memory 1104 and
divided up into directional bins versus time or depth (or both). The hole depth
may be known at the time of the azimuthal measurement or later added based on
depth versus time data, which may be measured at the surface. The binned data
can be used to correlate the measurement versus a depth and orientation. In this
manner, an angular profile of the formation charactersitics around the
circumference of a tool string or bore hole can be measured while the azimuthal
formation sensor 680 rotates.
[0089] The survey direction sensor 1106 can provide information about the
orientation of the formation sensor 1108 to the controller 1102. The shaft position
sensor 1112 can provide information to the controller 1102 about the position of
the formation sensor 1108 relative to a rotating shaft (such as shaft 654
described above with respect to FIG. 7) that causes the formation sensor 1108 to
rotate. The housing position sensor 1116 can provide information to the
controller 1102 about the angular position relative to a tool string of a housing
(such as housing 656 described above with respect to FIG. 7) supporting the
formation sensor 1108. In some aspects, the survey direction sensor 1106 may
provide direct information about the orientation of the formation sensor 1108,
similar to the manner described above with respect to FIGs. 2-3, in which the
angular position sensors 224 or 225 can be positioned for rotating respectively
with the rotatable transmit antenna 216 or the rotatable receive antenna 218 to
indicate an angular position thereof. In some aspects, the survey direction
sensor 1106 may provide indirect information about the orientation of the
formation sensor 1108 that can be supplemented by information from the shaft
position sensor 1112 or the housing position sensor 1116, similar to the manner
described above with respect to FIG. 5, in which data from the survey direction
sensor 325 can be combined with data from the orientation sensor 368 to
determine an angular position of the antenna 316.
[0090] The time synchronizer 1118 can include a clock or other time
reference device. The time synchronizer can provide a common time scale for
the controller 1102 for synthesizing the various measurements received from the
various components. The controller 1102 can control a rate of rotation of the
formation sensor 1108 via the rate controller 1120. For example, the rate
controller 1120 can control the rotation rate of a motor rotating the formation
sensor 1108. The rate controller 1120 can form all or part of an information
handling system, which may include or interface with other information handling
systems described herein.
[0091] The communications device 1114 can communicate information to
or from the controller 1102. For example, the communications device 1114 can
communicate information from the controller to the surface or to another tool in
the tool string. One example of the communications device 1114 is a toroid for
short hop communications, as discussed above with respect to FIG. 7 . The
toroid can wrap circumferentially around a carrier of the toroid. In some aspects,
the communications device 1114 can communicate synthesized information or
raw data about the formation sensor 1108 to the system control center 1002
(described above with respect to FIG. 11) as information about one or more of
any of the transmitters 1004a-n or receivers 1006a-m.
[0092] FIG. 13 is a flow chart illustrating an example method 1200 for
measuring anisotropic characteristics of a subterranean formation according to
one aspect. The method can utilize a bottom hole sensor assembly as described
herein, such as the bottom hole sensor assembly 214 described above with
respect to FIGs. 2-3 or variations thereof, such as described with respect to other
figures herein.
[0093] In block 1210, a first signal is transmitted via a transmit antenna.
For example, the rotatable transmit antenna 216 can transmit the signal into the
formation 210. In block 1220, a second signal associated with the first signal is
received via a receive antenna. The first signal can be transmitted or the second
signal can received as the transmit antenna or the receive antenna is rotating
relative to the tool string. For example, the rotatable receive antenna 218 can
receive a signal from the sensitive volume 226 of the formation 210 that
corresponds to a response of the formation 210 to the first signal transmitted by
the rotatable transmit antenna 216. The rotatable transmit antenna 216 or the
rotatable receive antenna 218 may be rotating as the signals are transmitted or
received.
[0094] In block 1230, an angular position of the transmit antenna or the
receive antenna is detected as the transmit antenna or the receive antenna
rotates relative to the tool string. For example, the angular position sensor 224 or
225 can detect the angular position in block 1230.
[0095] In block 1240, the second signal and the angular position can be
used to determine a characteristic of the subterranean formation at a position
relative to the bottom hole assembly. For example, the second signal can
indicate a resistivity of the formation 210 in the sensitive volume 226 and the
angular position can indicate the location of the sensitive volume 226 relative to
the tool string 212.
[0096] In some aspects, signals from multiple transmitter and receiver pairs
can be used in combination in determining the characteristic of the subterranean
formation. Determination may be carried out by performing simulations with a
formation characteristic value to produce modeled signals, computing a
difference between the modeled signals and signals from the transmitter and
receivers, and adjusting the formation characteristic value until a least difference
is achieved. The formation characteristic value corresponding to the least
difference may be accepted as final interpretation of the formation characteristic
measured by the signals of the transmitter and receiver pairs.
[0097] In some aspects, a bottom hole assembly can be provided including
a tool string and an azimuthal sensor rotatively coupled with the tool string such
that the azimuthal sensor is rotatable relative to the tool string. In some aspects,
a method can include rotating an azimuthal sensor relative to a tool string.
[0098] In some aspects, a bottom hole assembly, downhole system, a tool,
or a method is provided according to one or more of the following examples. In
some aspects, a tool, an assembly, or a system described in one or more of
these examples can be utilized to perform a method described in one of the other
examples.
[0099] Example # 1: Provided can be a downhole assembly, comprising a
tool string; a directionally-dependent transmitter coupled with the tool string; and
a directionally-dependent receiver coupled with the tool string, wherein at least
one of the directionally dependent receiver and the directionally dependent
transmitter is rotatable relative to the tool string.
[001 00] Example #2: Provided can be the downhole assembly of Example #
1, further comprising at least one angular position sensor arranged with a known
rotational relationship with the at least one of the transmitter or the receiver
rotatable relative to the tool string. The receiver may receive signals having
signal information. The at least one angular position sensor may detect an
angular position of at least one of the transmitter or the receiver. The signal
information and the angular position may be indicative of a characteristic of a
subterranean formation at a position relative to the tool string.
[001 01] Example #3: Provided can be the downhole assembly of any of
Examples #1-2, further comprising a communication unit communicatively
coupled with the receiver and the at least one angular position sensor. The
communication device may be communicatively coupled with the receiver for
transmitting the signal information. The communication device may be
communicatively coupled with the at least one angular position sensor for
transmitting the angular position.
[001 02] Example #4: Provided can be the downhole assembly of any of
Examples #1-2, further comprising a motor coupled with at least one of the
transmitter or the receiver, wherein the transmitter or the receiver is rotatable
relative to the tool string in response to the motor rotating.
[001 03] Example #5: Provided can be the downhole assembly of any of
Examples #1-4, further comprising a second motor and a drill bit rotatable in
response to the second motor rotating, wherein the motor coupled with the
transmitter or the receiver is rotatable independently of the second motor.
[001 04] Example #6: Provided can be the downhole assembly of any of
Examples #1-4, wherein the transmitter or the receiver is positioned uphole of the
motor.
[001 05] Example #7: Provided can be the downhole assembly of any of
Examples #1-4, wherein the transmitter or the receiver is positioned downhole of
the motor.
[001 06] Example #8: Provided can be the downhole assembly of any of
Examples #1-2, further comprising a motor and a drill bit rotatable in response to
the motor rotating, wherein the transmitter or the receiver is positioned at the drill
bit or adjacent to the drill bit.
[001 07] Example #9: Provided can be the downhole assembly of any of
Examples #1-2, wherein the transmitter or the receiver is rotatable relative to the
tool string in a direction opposite to a direction of rotation of the tool string.
[001 08] Example #10: Provided can be the downhole assembly of any of
Examples #1-2, wherein the transmitter is rotatable relative to the tool string and
the receiver is rotatable relative to the tool string.
[001 09] Example # 11: Provided can be the downhole assembly of any of
Examples #1-10, further comprising a motor coupled with the transmitter and the
receiver, wherein the transmitter and the receiver are rotatable together relative
to the tool string in response to the motor rotating.
[001 10] Example #12: Provided can be the downhole assembly of of any of
Examples #1-10, wherein the at least one angular position sensor includes a first
angular position sensor and a second angular position sensor, the downhole
assembly further comprising a first motor coupled with the transmitter, wherein
the transmitter is rotatable relative to the tool string in response to the first motor
rotating and the first angular position sensor is arranged with a first known
rotational relationship with the transmitter; and a second motor coupled with the
receiver, wherein the receiver is rotatable relative to the tool string in response to
the second motor rotating and the second angular position sensor is arranged
with a second known rotational relationship with the receiver. The first angular
position sensor may detect an angular position of the transmitter relative to the
tool string. The second angular position sensor can detect an angular position of
the receiver relative to the tool string.
[001 11] Example #13: Provided can be a system comprising a tool string; a
transmitter rotatable relative to the tool string; a first angular position sensor
arranged with a first known rotational relationship with the transmitter; a receiver
rotatable relative to tool string; a second angular position sensor arranged with a
second known rotational relationship with the receiver; and an information
handling system communicatively coupled with at least the receiver, the
information handling system comprising a processor and a memory device
coupled with the processor, the memory device containing a set of instructions
that, when executed by the processor, cause the processor to determine a
characteristic of a subterranean formation relative to the tool string based, at
least in part, on outputs received from the receiver, the first angular position
sensor, and the second angular position sensor. The first angular position sensor
may detect an angular position of the transmitter. The second angular position
sensor may detect an angular position of the receiver. Said outputs may include
a signal received by the receiver, the angular position of the transmitter, and the
angular position of the receiver.
[001 12] Example #14: Provided can be the system of Example #13, further
comprising a motor torsionally coupled with at least one of the transmitter or the
receiver for rotating the torsionally coupled antenna or antennas; and a motor
controller communicatively coupled with the motor and the information handling
system, wherein the set of instructions contained in the memory device of the
information handling system further comprise instructions that, when executed by
the processor, cause the processor to instruct the motor controller to control a
speed of the torsionally coupled antenna or antennas by controlling a speed of
the motor.
[001 13] Example #15: Provided can be the system of Example #13, wherein
the receiver comprises a receive antenna oriented substantially parallel to a
transmit antenna of the transmitter and at least one of the transmit antenna or the
receive antenna is tilted with respect to a longitudinal axis of the tool string,
wherein the set of instructions contained in the memory device of the information
handling system further comprise instructions that, when executed by the
processor, cause the processor to determine the characteristic of the
subterranean formation at a position ahead of an end of the tool string based, at
least in part, on the parallel orientation of the receive antenna and the transmit
antenna.
[001 14] Example # 6: Provided can be the system of Example #13, wherein
the receiver comprises a receive antenna oriented substantially perpendicular to
a transmit antenna of the transmitter, wherein the set of instructions contained in
the memory device of the information handling system further comprise
instructions that, when executed by the processor, cause the processor to
determine the characteristic of the subterranean formation at a position lateral to
the tool string in a direction lateral to a direction of travel of an end of the tool
string based, at least in part, on the perpendicular orientation of the receive
antenna and the transmit antenna.
[001 15] Example #17: Provided can be the system of Example #13, wherein
at least one of the transmitter or the receiver includes an antenna having a first
winding arranged in a first winding plane and a second winding arranged in a
second winding plane, the first winding being tilted relative to the second winding,
wherein the set of instructions contained in the memory device of the information
handling system further comprise instructions that, when executed by the
processor, cause the processor to determine the characteristic of the
subterranean formation at a first position in the first winding plane and at a
second position in the second winding plane based, at least in part, on respective
orientations of the receiver and the transmitter.
[001 16] Example #18: Provided can be a method comprising transmitting a
first signal via a transmitter coupled with a tool string in a subterranean formation;
receiving a second signal associated with the first signal via a receiver coupled
with the tool string, wherein the transmitter or the receiver is rotating relative to
the tool string; detecting an angular position of the transmitter or the receiver as
the transmitter or the receiver rotates relative to the tool string; and determining a
characteristic of the subterranean formation at a position relative to tool string
based, at least in part, on the second signal and the angular position.
[001 17] Example # 9: Provided can be the method of Example #18, wherein
using the second signal and the angular position to determine a characteristic of
the subterranean formation at a position relative to the tool string includes
determining a resistivity of a region of the formation at a distance from the tool
string and in a direction from the tool string.
[001 18] Example #20: Provided can be the method of any of Examples #18-
19, further comprising receiving a third signal associated with the first signal via a
second receiver coupled with the tool string at a position between the first
receiver and the transmitter, wherein the transmitter or the second receiver is
rotating relative to the tool string; if the second receiver is rotating relative to the
tool string, detecting a second angular position of the receiver as the second
receiver rotates relative to the tool string; using a first combination or a second
combination to determine the characteristic of the formation at a second position
relative to the tool string, the first combination including the third signal and the
first angular position, the second combination including the third signal and the
second angular position; and creating a profile of the characteristic of the
formation based, at least in part, on the determination of the characteristic of the
formation at the first position and the determination of the characteristic of the
formation at the second position.
[001 19] The foregoing description of the aspects, including illustrated
examples, of the disclosure has been presented only for the purpose of
illustration and description and is not intended to be exhaustive or to limit the
disclosure to the precise forms disclosed. Numerous modifications, adaptations,
and uses thereof will be apparent to those skilled in the art without departing from
the scope of this disclosure.
Claims
What is claimed is:
1. A downhole assembly, comprising:
a tool string;
a directionally-dependent transmitter coupled with the tool string; and
a directionally-dependent receiver coupled with the tool string, wherein at
least one of the directionally dependent receiver and the directionally dependent
transmitter is rotatable relative to the tool string.
2 . The downhole assembly of claim 1, further comprising:
at least one angular position sensor arranged with a known rotational
relationship with the at least one of the transmitter or the receiver rotatable
relative to the tool string.
3 . The downhole assembly of claim 2, further comprising a communication
unit communicatively coupled with the receiver and the at least one angular
position sensor.
4 . The downhole assembly of claim 2, further comprising:
a motor coupled with at least one of the transmitter or the receiver, wherein
the transmitter or the receiver is rotatable relative to the tool string in response to
the motor rotating.
5 . The downhole assembly of claim 4, further comprising a second motor and
a drill bit rotatable in response to the second motor rotating, wherein the motor
coupled with the transmitter or the receiver is rotatable independently of the
second motor.
6 . The downhole assembly of claim 4, wherein the transmitter or the receiver
is positioned uphole of the motor.
7 . The downhole assembly of claim 4, wherein the transmitter or the receiver
is positioned downhole of the motor.
8 . The downhole assembly of claim 2, further comprising a motor and a drill
bit rotatable in response to the motor rotating, wherein the transmitter or the
receiver is positioned at the drill bit or adjacent to the drill bit.
9 . The downhole assembly of claim 2, wherein the transmitter or the receiver
is rotatable relative to the tool string in a direction opposite to a direction of
rotation of the tool string.
10. The downhole assembly of claim 2, wherein the transmitter is rotatable
relative to the tool string and the receiver is rotatable relative to the tool string.
11. The downhole assembly of claim 10, further comprising a motor coupled
with the transmitter and the receiver, wherein the transmitter and the receiver are
rotatable together relative to the tool string in response to the motor rotating.
12. The downhole assembly of claim 10, wherein the at least one angular
position sensor includes a first angular position sensor and a second angular
position sensor, the downhole assembly further comprising:
a first motor coupled with the transmitter, wherein the transmitter is
rotatable relative to the tool string in response to the first motor rotating and the
first angular position sensor is arranged with a first known rotational relationship
with the transmitter; and
a second motor coupled with the receiver, wherein the receiver is rotatable
relative to the tool string in response to the second motor rotating and the second
angular position sensor is arranged with a second known rotational relationship
with the receiver.
A system comprising
a tool string;
a transmitter rotatable relative to the tool string;
a first angular position sensor arranged with a first known rotational
relationship with the transmitter;
a receiver rotatable relative to tool string;
a second angular position sensor arranged with a second known rotational
relationship with the receiver; and
an information handling system communicatively coupled with at least the
receiver, the information handling system comprising a processor and a memory
device coupled with the processor, the memory device containing a set of
instructions that, when executed by the processor, cause the processor to
determine a characteristic of a subterranean formation relative to the tool string
based, at least in part, on outputs received from the receiver, the first angular
position sensor, and the second angular position sensor.
14. The system of claim 13, further comprising:
a motor torsionally coupled with at least one of the transmitter or the
receiver for rotating the torsionally coupled antenna or antennas; and
a motor controller communicatively coupled with the motor and the
information handling system, wherein the set of instructions contained in the
memory device of the information handling system further comprise instructions
that, when executed by the processor, cause the processor to instruct the motor
controller to control a speed of the torsionally coupled antenna or antennas by
controlling a speed of the motor.
15. The system of claim 13, wherein the receiver comprises a receive antenna
oriented substantially parallel to a transmit antenna of the transmitter and at least
one of the transmit antenna or the receive antenna is tilted with respect to a
longitudinal axis of the tool string, wherein the set of instructions contained in the
memory device of the information handling system further comprise instructions
that, when executed by the processor, cause the processor to determine the
characteristic of the subterranean formation at a position ahead of an end of the
tool string based, at least in part, on the parallel orientation of the receive
antenna and the transmit antenna.
16. The system of claim 13, wherein the receiver comprises a receive antenna
oriented substantially perpendicular to a transmit antenna of the transmitter,
wherein the set of instructions contained in the memory device of the information
handling system further comprise instructions that, when executed by the
processor, cause the processor to determine the characteristic of the
subterranean formation at a position lateral to the tool string in a direction lateral
to a direction of travel of an end of the tool string based, at least in part, on the
perpendicular orientation of the receive antenna and the transmit antenna.
17. The system of claim 13, wherein at least one of the transmitter or the
receiver includes an antenna having a first winding arranged in a first winding
plane and a second winding arranged in a second winding plane, the first winding
being tilted relative to the second winding, wherein the set of instructions
contained in the memory device of the information handling system further
comprise instructions that, when executed by the processor, cause the processor
to determine the characteristic of the subterranean formation at a first position in
the first winding plane and at a second position in the second winding plane
based, at least in part, on respective orientations of the receiver and the
transmitter.
18. A method comprising:
transmitting a first signal via a transmitter coupled with a tool string in a
subterranean formation;
receiving a second signal associated with the first signal via a receiver
coupled with the tool string, wherein the transmitter or the receiver is rotating
relative to the tool string;
detecting an angular position of the transmitter or the receiver as the
transmitter or the receiver rotates relative to the tool string; and
determining a characteristic of the subterranean formation at a position
relative to tool string based, at least in part, on the second signal and the angular
position.
19. The method of claim 18, wherein using the second signal and the angular
position to determine a characteristic of the subterranean formation at a position
relative to the tool string includes determining a resistivity of a region of the
formation at a distance from the tool string and in a direction from the tool string.
20. The method of claim 18, further comprising:
receiving a third signal associated with the first signal via a second
receiver coupled with the tool string at a position between the first receiver and
the transmitter, wherein the transmitter or the second receiver is rotating relative
to the tool string;
if the second receiver is rotating relative to the tool string, detecting a
second angular position of the receiver as the second receiver rotates relative to
the tool string;
using a first combination or a second combination to determine the
characteristic of the formation at a second position relative to the tool string, the
first combination including the third signal and the first angular position, the
second combination including the third signal and the second angular position;
and
creating a profile of the characteristic of the formation based, at least in
part, on the determination of the characteristic of the formation at the first position
and the determination of the characteristic of the formation at the second
position.