APPARATUS AND METHODS FOR GEOSTEERING
Technical Field
The present invention relates generally to apparatus and methods for making
measurements related to oil and gas exploration.
Background
In drilling wells for oil and gas exploration, understanding the structure and
properties of the associated geological formation provides information to aid such
exploration. In addition, it may be critical to acquire optimal wellbore placement to
enhance maximum oil production. An azimuthal directional electromagnetic (EM)
resistivity tool has been implemented to actively adjust borehole position so that an
optimized well plan can be achieved. A related application of such a tool is
geosteering, which is an intentional control to adjust drilling direction. A geosignal
is a signal or representation that can be used for geosteering. Azimuthal geosignal
responses can be used to guide well path orientation in real-time as well as steer the
well towards a desired formation zone It is widely known that existing azimuthal
EM tools used in geosteering suffer a "blind-spot" problem in a drilling condition
where the logging tool is located at layered formation media with symmetric
resistivity profiles. In such circumstances, geosignal responses of current
(conventional) directional EM tools become very insensitive to such layered
formation effects so that petrophysicists may misinterpret the formation geology
based on conventional geosignal signals. An example of an extremely difficult
formation case includes a tool located in the middle layer of a symmetric 3-layer
formation resistivity profile, where the middle layer has a higher resistivity value
than both the upper and the lower layers. In this drilling condition, the geosignal is
very weak and petrophysicists may make the wrong impression that the tool is
drilling in a homogenous formation medium.
WO 2011/129828 Al discusses various embodiments that include apparatus
and methods of processing and geosteering with respect to well logging. Methods
and associated apparatus can include acquiring signals generated from operating a
tool rotating in a borehole of a well, where the tool includes a receiver antenna tilted
with respect to the longitudinal axis of the tool and two transmitter antennas. The
acquired signals can be processed with respect to a direction in the rotation of the
tool to determine properties associated with a formation and/or to determine a
geosignal for geosteering a drilling operation. WO 2011/129828 Al includes
discussion of converting acquired signals to coupling components.
US Patent Publication 2008/0078580 relates to systems and methods for
performing bed boundary detection and azimuthal resistivity logging with a single
tool. Some method embodiments include logging a borehole with an azimuthallysensitive
resistivity logging tool; deriving both a resistivity log and a boundary
detection signal from measurements provided by said tool; and displaying at least
one of the boundary detection signal and the resistivity log. The resistivity log
measurements may be compensated logs, i.e., logs derived from measurements by
one or more symmetric transmitter-receiver arrangements. Though symmetric
arrangements can also serve as the basis for the boundary detection signal, a greater
depth of investigation can be obtained with an asymmetric arrangement. Hence the
boundary detection signal may be uncompensated.
Brief Description of the Drawings
Figure 1 shows a block diagram of an embodiment of an example apparatus
having a tool structure operable in a borehole to determine formation properties, in
accordance with various embodiments.
Figure 2 shows a representation of an example antenna configuration of a
multi-component electromagnetic logging tool, in accordance with various
embodiments.
Figure 3 shows a tool operable an azimuthal deep resistivity sensor, in
accordance with various embodiments.
Figures 4A-4B show a three-layer formation with symmetric resistivity
structures and geosignal phase responses of the tool configuration of Figure 2
operating along a path in the three-layer formation, in accordance with various
embodiments.
Figures 5A-5B show a three-layer formation without symmetric resistivity
structures and geosignal phase responses of the tool configuration of Figure 2
operating along a path in the three-layer formation, in accordance with various
embodiments.
Figure 6A-C show magnetic field responses associated with transmitter T6
and receiver Rl in the tool configuration of Figure 3 in the formation model in
Figure 3A, in accordance with various embodiments.
Figure 7A-C show magnetic field responses associated with XX and YY
components in the formation model in Figure 4A, in accordance with various
embodiments.
Figure 8 shows a configuration of an antenna system equipped with a tilted
receiver and a tilted transmitter, in accordance with various embodiments.
Figure 9 shows a configuration of tool bin positions and corresponding
azimuthal angles, in accordance with various embodiments.
Figure 10 shows a configuration of an electromagnetic tool equipped with
both tilted transmitters and tilted receivers, in accordance with various
embodiments.
Figures 11A-l IB show geosignal responses of a first kind of the tool
configuration in Figure 10 in the formation model in Figure 6A, in accordance with
various embodiments.
Figures 12A-12B show geosignal responses of a second kind of the tool
configuration in Figure 10 in the formation model in Figure 6A, in accordance with
various embodiments.
Figures 13A-13B show geosignal images of a first kind of the tool
configuration in Figure 10 in the formation model in Figure 6A, in accordance with
various embodiments.
Figures 14A-14B show geosignal images of a second kind of the tool
configuration in Figure 10 in the formation model in Figure 6A, in accordance with
various embodiments.
Figures 15A-D show antenna configurations operable to acquire
compensated geosignal responses, in accordance with various embodiments.
Figure 16 shows features of an example method of conducting a drillingrelated
activity with respect to a geosignal, in accordance with various
embodiments.
Figure 17 depicts a block diagram of features of an example system operable
to make measurements in a borehole and process measured signals to conduct a
drilling-related activity with respect to a geosignal, in accordance with various
embodiments.
Figure 18 depicts an embodiment of a system at a drilling site, where the
system includes a measurement tool and processing unit operable to conduct a
drilling-related activity with respect to a geosignal, in accordance with various
embodiments.
Detailed Description
The following detailed description refers to the accompanying drawings that
show, by way of illustration and not limitation, various embodiments in which the
invention may be practiced. These embodiments are described in sufficient detail to
enable those skilled in the art to practice these and other embodiments. Other
embodiments may be utilized, and structural, logical, and electrical changes may be
made to these embodiments. The various embodiments are not necessarily mutually
exclusive, as some embodiments can be combined with one or more other
embodiments to form new embodiments. The following detailed description is,
therefore, not to be taken in a limiting sense.
Control of geosteering can be based on downhole logging measurements to
increase the borehole's exposure to a hydrocarbon-bearing formation (the
"payzone"). Such geosteering can be used to maintain a wellbore within a region
that provides a material that is a source of economic value. Capabilities of
geosignals are useful in geosteering to optimize well placement for maximum oil
recovery. Geosignals, indicative of the direction of drilling tools downhole, are
capable of detecting boundaries. In addition, the geosignal can be used for the
calculation of distance to bed boundaries. Apparatus and processing schemes, as
discussed herein, allow for the generation of geosignals.
Figure 1 shows a block diagram of an embodiment of an apparatus 100
having a tool structure 105 operable in a borehole to determine formation properties.
The tool structure 105 includes an arrangement of sensors 110-1, 110-2 . . . 110-(N-
1), 110-N along a longitudinal axis 107 of tool 105. Each sensor 110-1, 110-2 . . .
HO-(N-l), 110-N can be tilted with respect to the longitudinal axis 107. A tilted
sensor is one that is disposed on the tool structure 105 at a selected angle that is
greater than tolerance angles associated with a sensor attached placed in parallel or
perpendicular to the longitudinal axis 107. The term "tilted" indicates that the plane
of the sensor is not perpendicular to the longitudinal axis 107. A tilt angle can be
measured from the longitudinal axis 107 to a normal to the plane of the sensor, and
can be referred to as a positive or negative angle less than 90°. Typically, the tilt
angle ranges in absolute value from 5° to 85°. The arrangement of sensors can
include one or more combinations of transmitting sensors and receiving sensors
having tilt angles. A configuration of the transmitting sensors and receiving sensors
can form a symmetric sensor tool.
The tool structure 105 can include one or more sets of transmitting sensors
and receiving sensors arranged symmetrically and one or more sets of transmitting
sensors and receiving sensors that are not arranged symmetrically. A symmetric or
non-symmetric arrangement can be realized by selectively controlling selected ones
of the sensors 110-1, 110-2 . . . llO-(N-l), 110-N for transmitting and selected ones
of the sensors 110-1, 110-2 . . . llO-(N-l), 110-N for receiving. Operation of a
symmetric sensor tool allows for structural compensation to generate compensation
signals that can be processed to determine formation parameters. The processing of
selected signals received correlated to generating selected signals can produce
geosignals that may be used to provide accurate readings for anisotropic
measurements and accurate evaluation of formations in both wireline applications
and measurements-while-drilling (MWD) applications such as logging-whiledrilling
(LWD) applications.
In various embodiments, arrangements of sensors as taught herein can
include the use of a variety of sensors. For example, both transmitting sensors and
receiving sensors can be antennas. Sensors can be realized as one of a coil, a
solenoid, a magnetometer, or other similar sensor. In case of coil sensors, a tilt
angle may be produced by winding the coil with an angle. In case of a solenoid, the
elevation angle of the core may be adjusted for the desired tilt angle. In case of a
magnetometer, the device may be mounted onto or into the tool structure 105 with
the desired tilt angle.
The apparatus 100 can include a control unit 120 that manages the
generation of transmission signals and the collection of received signals
corresponding to the transmission signals. The control unit 120 can be structured to
be operable to select specific ones of the sensors 110-1, 110-2 . . . llO-(N-l), 110-N
as transmitting sensors and receiving sensors to form a symmetric sensor tool. The
control unit 120 can control the firing of selected transmitting sensors and the
acquisition of signals from selected receiving sensors such that the measured signals
can be used to generate compensated signals related to coupling components as
taught herein. The firing of a sensor means the generation of a transmission signal
from the sensor. The generation of transmission signals can be conducted to
provide signals of different frequencies. Each of the different frequencies can be
associated with a different transmitting sensor. The collected received signals can
be provided to a processing unit 130 in appropriate format to perform numerical
inversion on data generated from signals acquired at receiving sensors in the
arrangement of sensors 110-1, 110-2 . . . HO-(N-l), 110-N.
The processing unit 130 can be structured to process measured signals to
generate geosignals. The scheme for generating the geosignals can be performed in
accordance with various embodiments discussed herein. The processing unit 130
can apply an inversion process to generate formation parameters. Performing an
inversion operation or inversion operations can include using a forward model
and/or a library. A forward model provides a set of mathematical relationships for
sensor response that can be applied to determining what a selected sensor would
measure in a particular environment, which may include a particular formation. A
library can include information regarding various formation properties that can be
correlated to measured responses to selected probe signals. Performing an inversion
operation or inversion operations can include performing an iterative process or
performing a pattern matching process.
The processing unit 130 can be structured to process measured signals to
generate geosignals. These geosignals can be based on sensitivity of XX and YY
coupling components. Geosignals based on XZ and ZX coupling components also
can be generated. Drilling operations, such as but not limited to geosteering, can be
conducted using the geosignals based on the sensitivity of XX and/or YY coupling
components. Use of the geosignals based on the sensitivity of XX and YY coupling
components can include evaluation in combination with geosignals based on XZ
and/or ZX coupling components. The processing unit 130 can be arranged as a
separate unit from the control unit 120 or integrated with the control unit 120.
Either or both of the processing unit 130 and the control unit 120 can be constructed
as distributed components.
In various embodiments, the measurement tool 105 with the processing unit
130 or combination of the control unit 120 and the processing unit 130 can be
arranged to determine and generate XX and YY coupling components that include
sensitivity of both XX and YY coupling components to differentiate between null
signals of conventional tools in a "blind-spot" and in homogeneous medium. The
sensitivity of XX and YY coupling components may be provided by processing to
decouple coupling components of a coupling matrix that relates signals received at
receiving sensors of the tool 105 to signals transmitted by transmitting sensors of
the tool 105, by arrangement of transmitting sensors and receiving sensors that
directly provides decoupled XX and YY coupling components, or by arrangement
of transmitting sensors and receiving sensors that provides decoupled XX and YY
coupling components with limited processing. Different geosignals can be
generated according to different combinations of coupling components that utilize
XX and YY sensitivity to resolve "blind-spot" issues. Such combinations may
include, but are not limited to, generating an arithmetic mean that can include a
determination of variation between XX and YY coupling components, or a
geometric mean that can include a determination of variation between XX and YY
coupling components, or other combinations taught herein. The determination of a
variation or amount of variation can be used to identify boundaries between
different formation layers.
In various embodiments, processing techniques along with an EM tool
equipped with both tilted transmitter (s) and tilted receiver(s) can be implemented to
provide geosignal signals. Geosignal responses can be utilized to differentiate
formation models among several cases that are unable to be resolved by
conventional azimuthal EM tools. The new techniques can remove the "blind-spot"
problem and better assist petrophysicists to understand formation geology based on
various geosignal responses sensitive to specific azimuthal orientations. These
techniques may meet particular needs in advanced geosteering applications.
Figure 2 shows an antenna configuration 200 for a multi-component
electromagnetic logging tool. Discussions of such a configuration of a multicomponent
electromagnetic logging tool can be found in International Publication
WO201 1/129828. The magnetic field h in the receiver coils can be represented in
terms of the magnetic moments m at the transmitters and a coupling matrix C as:
h = C m (1)
Equation (1) can be expressed as
where Mc, Mg, and M are the magnetic moments of the transmitted signal emitted
by transmitters Tc, Tg, and Tz , respectively. Hc, H g, and H are the magnetic fields
which are proportional to the received signal at the receiver antennas Rx, Ry, and R z ,
respectively. For the antenna configuration of Figure 2, nine absolute or differential
measurements can be obtained when an antenna is fired and a signal is measured at
each of the three receivers respectively. These nine measurements enable the
determination of the complete coupling matrix C. The coupling matrix C has
components, C = a V/ , where is the index of receiver Rx, Ry, and Rz, J is the
index of receiver Tc, Tg, and Tz, a is a constant coefficient determined by the tool
design, V/ is a coupling component representing the signal amplitude and phase
shift measured by receiver in response to the firing of transmitter J.
Figure 3 shows a tool 305 operable as an azimuthal directional resistivity
EM tool. The tool configuration 305 may be operable to provide azimuthal deep
sensing. With tilt receivers (Rl, R2, and R3), the tool configuration enables
azimuthal sensitive measurements. The measurements made by the tool 305 are
associated with coupling components of and in Figure 2, providing azimuthal
resistivity and geosignal responses to detect bed boundary while tool is rotated
during drilling operation. The configuration and operation of the tool 305 are
discussed in US Patent Publication 2008/0078580. The tool 305 can acquire
measurements in a number of discrete directions, called bins or bin directions,
allowing for a number of different depths of investigation to determine distance and
direction to multiple bed boundaries. For example, the tool 305 can be arranged
with transmitters and receivers to use 32 discrete directions and 14 different depths
of investigation. However, other arrangements of tools similar to the tool 305 can
use more or less than 32 discrete directions and/or more or less than 14 different
depths of investigation.
The tool 305 includes transmitters T1-T6 and tilted receivers R1-R3 to
measure resistivity that can be structured to provide an azimuthal resistivity array by
activating different transmitters in combination with selecting appropriate titled
receivers to collect responses from activating the different transmitters. The
transmitters spaced apart at different distances with respect to the tilted receivers
allow investigation of a formation at different distances from tool 305 including
relatively deep probing. Deeper readings provided by the tool 305 can improve
reaction time, allowing for increased drilling speed. The arrangement of tilted
sensors also provides for azimuthal measurements. The azimuthal readings can
provide for derivation of anisotropy resistivity values, ¾ (horizontal) and Rv
(vertical) and dip. The azimuthal measurements may be conducted for a number of
bins. For example, the number of bins can be set at 32 bins. The number of bins
can be set to another number.
The transmitters and receivers of the tool 305 can be spaced to provide a set
of separation distances. For example, the upper transmitters can be spaced apart
from the central tilted receivers at the same separation distances of the lower
transmitters spaced apart from the central tilted receivers. Such a configuration
provides a symmetric arrangement of sensors that can be grouped to provide a
plurality of sub-arrays. Example separation distances can include separation
distances of 16 inches, 32 inches, and 48 inches. Other separation distances can be
used. In addition, there are separation distances that can be used that are not in a
symmetric arrangement such as using the upper and lower transmitters with the
remote titled receiver, R3, which can provide longer separation distances. In
addition, tool 305 can be operated at a set of different frequencies. For example,
tool 305 can be operated at frequencies including, but not limited to, 2 MHz, 500
KHz, and 125 KHz.
However, there are issues with using geosignal responses in several
formation models, especially for a layered model with symmetric resistivity
structures. Consider a three-layer formation model. Figure 4A shows the tool of
Figure 3 drilled in a three-layer formation model along a path 407, where the upper
and the lower layers have low resistivity of IW-m and the middle layer has high
resistivity of 20W·ih. Figure 4B displays the corresponding geosignal phase
response 441 for the tool's high side direction and the corresponding geosignal
phase response 442 for low side direction. High side direction (shown in Figure 9)
describes that the tool's face is pointing to the surface with azimuthal angle of 0°,
whereas low side direction is 180° opposite to the high side direction. As illustrated
in Figures 4A-4B, when the tool is located at true vertical direction (TVD) of 15
feet, the geosignal phase becomes null regardless of the drilling dip angle. Under
this circumstance, petrophysicists may consider the formation geology as a
homogeneous medium owing to tiny geosignal responses.
Similar situations occur if the lowest layer resistivity is changed to 5W·ih as
shown in Figure 5A, with the tool of Figure 3 drilled in a three-layer formation
model along a path 507. Figure 5B displays the corresponding geosignal phase
response 541 for the tool's high side direction and the corresponding geosignal
phase response 542 for low side direction. At TVD around 12 feet in Figures 5A-
5B, the corresponding geosignal phase remains null similar to the responses of a
homogeneous formation case. As it can be seen from these figures for the tool of
Figure 3, regardless of what the resistivities are, there is a "blind-spot" where
geosignal (or equivalently ) becomes zero in the three-layer scenario where
middle layer is more resistive compared to the others. Other example formations,
such as the middle layer being more conductive compared to the upper layer and the
lower layer in a three-layer scenario, or multi-layer scenario, with resistivity profiles
in high-low-high sequence or low-high-low sequence, could create such a "blindspot"
in geosignal responses of conventional LWD azimuthal directional resistivity
EM tools.
As mentioned above, geosignal responses of an azimuthal directional
resistivity EM tool, currently in commercial use, are associated with coupling
components of and , and the azimuthal sensitivity is only related to
coupling components (See International Publication WO 201 1/129828). Figure
6A shows a formation model, where Figure 6B shows the real part of the magnetic
field and Figure 6C the imaginary part of the magnetic field using transmitter T6
and receiver Rl of Figure 3. Figures 6B-C show the modeling responses of
magnetic field related to ZX and ZZ coupling components. Curves 641 and 643 are
for H and curves 642 and 644 are for Hzz- The formation model is set the same as
Figure 4A, but has constant relative dip angle of 89°. As depicted in Figures 6B-6C,
H coupling components become very small while tool is located in the middle of
the formation model (TVD at 15ft). Consequently, the azimuthal directional
resistivity EM tool loses azimuthal sensitivity while encountering such formation
models. Indeed, other kinds of symmetric layered formation models can make
geosignal useless at certain depth location so that ambiguity issues are raised for
conventional geosteering applications.
To resolve the ambiguities mentioned above in geosignal applications, new
geosignal responses are introduced herein. As shown in Figures 6B-6C, the ZX
coupling component loses sensitivity in the middle of the formation model (indeed,
XZ coupling component will be similar as ZX), and ZZ coupling component cannot
be utilized to provide azimuthal sensitivity. Therefore, two more coupling
components are introduced to geosignal responses; that is, XX and YY coupling
components.
Figure 7A shows the same formation model as Figure 6A, and the same
frequency and the antenna spacing (transmitter T6 and receiver Rl of Figure 3) are
used in Figures 7B-7C. Figures 7B-7C show the H field responses associated with
XX and YY coupling components. Curves 741 and 743 are for Hcc and curves 742
and 744 are for Hgg . In theory, coupling components of XX and YY are identical in
a homogeneous formation model. As shown in Figures 7B-7C, there are always
separations between XX and YY of the magnetic field, and thereby such separations
can be utilized to address the ambiguities above. Increases in theses separations
over distance can be used to identify boundaries between formation layers of
different resistivities.
The tilted transmitter and tilted receiver configuration 800 in Figure 8 was
discussed in International Publication WO201 1/129828, where the configuration
800 can be operable to provide XX and YY components in LWD logging tools. In
Figure 8, the received signal at the receiver (R) with respect to the firing of the
transmitter (7) can be expressed as equation (3).
= - s 2b + (Cx + ) cos b + (C + + (3)
where
Cxx = si si ; Cxy = sin sin ; Cxz = sin cos
Cyx = sin Q, sin ; w = V sin , sin ; w = sin Q, cos .
C =VZco Q ; = cos sin ; = cos 0, cos 0
In addition, two kinds of geosignal definitions (VGeol and VGeo2 ) were introduced in
US Patent Publication 2008/0078580; the first kind of geosignal is defined by
VGeol (i º 1
n ί ) = ,N (4)
i=l
and the other is expressed as
where i is the index of bin number of a rotating tool, ί is the corresponding
azimuthal angle from high side to the bin with index i as shown in Figure 9, is
the azimuthal angle of bin j opposite to the azimuthal direction of bin i, and N is the
total number of bins in Figure 9.
Consider the antenna design 1000 in Figure 10. With symmetric antenna
structures, geosignal responses described in equations (4) and equation (5) can be
compensated. Using the same drilling conditions as Figure 6A, a first kind of
geosignal, VGe , of compensated geosignal phase response and attenuation response
at four different tool azimuthal angles (0°, 90°, 180°, and 270°) are shown in Figure
11A and Figure 11B, respectively. Curve 1141 is for 0° azimuthal angle. Curve
1142 is for 90° azimuthal angle. Curve 1143 is for 180° azimuthal angle. Curve
1144 is for 270° azimuthal angle. Curve 1146 is for 0° azimuthal angle. Curve
1147 is for 90° azimuthal angle. Curve 1148 is for 180° azimuthal angle. Curve
1149 is for 270° azimuthal angle. Using the same drilling conditions as Figure 6A,
a second kind of geosignal, VGeo2 , of compensated geosignal phase response and
attenuation response at four different tool azimuthal angles (0°, 90°, 180°, and 270°)
are shown in Figure 12A and Figure 12B, respectively. Curve 1241 is for 0°
azimuthal angle. Curve 1242 is for 90° azimuthal angle. Curve 1243 is for 180°
azimuthal angle. Curve 1244 is for 270° azimuthal angle. Curve 1246 is for 0°
azimuthal angle. Curve 1247 is for 90° azimuthal angle. Curve 1248 is for 180°
azimuthal angle. Curve 1249 is for 270° azimuthal angle. As shown in Figures
1lA-1 IB, the first kind of geosignal never goes null even if tool is located in the
middle of the formation model. On the other hand, the second kind of geosignal
responses are similar to the azimuthal directional resistivity EM tool, where
ambiguities are found at such symmetric formation model.
Consequently, combination of both kinds of geosignal responses may be
utilized to distinguish between homogeneous formation model and inhomogeneous
layered formation model with symmetric resistivity profiles. In fact, Figures 13A-
13B show the geosignal phase image and the geosignal attenuation image of the first
kind with respect to different tool azimuthal angles corresponding to the signals in
Figure 11A and Figure 11B, respectively, in the formation model in Figure 6A.
Figures 14A-14B show the geosignal phase image and the geosignal attenuation
image of the second kind with respect to different tool azimuthal angles
corresponding to the signals in Figure 12A and Figure 12B, respectively, in the
formation model in Figure 6A. Using such geosignal images, petrophysicists can
interpret formation geology without ambiguity issues.
When an EM tool located in the middle of a symmetrical layered formation
or other formations), the difference of XX and YY components can remove the
blind- spot. Therefore, utilization of such a difference between XX and YY
components provides a mechanism to distinguish all described layered formation
models from a homogeneous formation model. In the tool configuration in Figure
10, the transmitters are perpendicular to the receivers and all antennas are tilted at
45 degrees. For such configuration, the voltage signal measured at a receiver in
response to a transmitter's firing can be presented, as described in equation (3), as:
V - V V - V 2V - V - V nt b)=- " yy cos 2 - cos + " (6)
So equation 4, using equation (6), can be represented as
V = i =l ... N
(7)
and equation (5), can be represented as
V - Vyy .. Vxz - Vzx , 2V - Vcc - Vyy
V i - - C 4
" P ) xx - V
yy_ 2 + Q0) _ V - Vzx + + 2V - V° - V
(8)
As indicated in equations (7) and (8), for different azimuthal angle at different
bin i, VGeol includes both variations between XX and YY and between XZ and ZX,
which is capable to determine the ambiguity associated with the blind spot using
conventional techniques. However, the VGeo2 geosignal only observes the variations
of XZ and ZX, which is similar to conventional commercial directional azimuthal
EM tools that utilize ZX components.
On the other hand, for the tool configuration in Figure 10, a processing unit
V - V V - V 2V - V - V
can decouple — cos 2/? , — x cos b , and -—-^- —by
applying a fitting function and/or Fourier transform to equation (3). Then, a
geosignal response of a third kind can be calculated and enerated as
and a geosignal response of a fourth kind
V - V
vGeo4 ( º (10)
zz xx yy
Geosignal can be used to solve the ambiguity issue, and geosignal
V Geo4 generated is similar to geosignal responses of conventional commercial tools.
New geosignals can be generated to reflect the differences in XX and YY
components to remove blind spot ambiguities.
In addition to using the value of the difference between XX and YY
coupling components, other geosignal responses can be also defined by, but not
limited by, the value of the ratio between XX and YY coupling components or the
value of the square root of XX and YY coupling components. Other algebraic
functions of XX and YY can also be used. Such values can be calculated on the
basis of magnetic field and/or complex voltage signals. The use of the square root
can be obtained by multi-component tools with configuration of Figure 2, for
example. By acquiring all coupling components, one can generate and simulate
geosignal responses using combinations of coupling components that include XX
and YY coupling components to differentiate between null signals of associated
with conventional tools in a "blind-spot" and in homogeneous medium. For
example, the tool configurations of Figures 15C and 15D can be used to decouple
all coupling components. Asymmetrical tool configurations can be utilized along
with a depth shift technique to achieve such decoupling. With the decoupled
components, different geosignal responses can be generated as functions of
combinations of coupling components related to, but not limited to, (XXYY)/(
XX+YY+2ZZ), (XX-YY)/(XX+YY-2ZZ), XX/ZZ and YY/ZZ, (XX-YY)/ZZ
and (XX+YY)/ZZ, XX/(XX+YY+2ZZ) and YY/(XX+YY+2ZZ), or XX/(XX+YY-
2ZZ) and YY/(XX+YY-2ZZ) that have capabilities to solve the ambiguity issue.
By examining and using XX and YY coupling components, the ambiguity issues of
conventional geosteering applications can be resolved.
Embodiments of the geosignal responses above may be obtained by different
configurations with both transmitter (s) and receiver(s) tilted. In addition, one can
use at least one tilt transmitter and at least one tilt receiver to achieve the geosignal
responses taught herein. Several possible configurations are also shown in Figures
15A-15D to enable compensated signals, where compensation can be achieved
between same bin data or opposite bin data associated with the upper and the lower
azimuthal measurements. For example, the upper means data from Ti-R and the
lower means data from T2-R in the configuration of Figure 15A. Owing to antenna
reciprocity, a transmitter and a receiver can be exchangeable in Figures 15A-15D.
Figure 16 shows features of an embodiment of an example method of
conducting a drilling-related activity with respect to a geosignal. At 1610, signals
are acquired where the signals are or have been generated from operating a tool in a
borehole. The tool, having a longitudinal axis, can include one or more transmitting
sensors tilted with respect to the longitudinal axis and one or more receiving sensors
tilted with respect to the longitudinal axis. The acquired signals can include signals
received at the one or more tilted receiving sensors in response to firing the one or
more tilted transmitting sensors. Firing of transmitting sensors can include
controlling the firing such that the transmitting sensors are conducted separately.
Acquiring the signals can include collecting a signal at each receiving sensor
separately with respect to separately fired transmitting sensors. Acquiring signals
can include acquiring compensated signals. Acquiring signals can include acquiring
voltage signals generated from operating the tool having a symmetric arrangement
of the one or more tilted transmitting sensors and the one or more tilted receiving
sensors. Acquiring signals can include acquiring voltage signals generated from
operating the tool to selectively activate selected transmitting sensors of the one or
more tilted transmitting sensors and to selectively collect the signals from selected
tilted receiving sensors of the one or more tilted receiving sensors such that the
selected transmitting sensors and the selected tilted receiving sensors are in a
symmetric arrangement with respect to the longitudinal axis. The one or more
transmitting sensors and the one or more receiving sensors can be, but are not
limited to, antennas tilted with tilt angle having a magnitude of 45° with respect to
the longitudinal axis or within one or two degrees of 45° such that the magnitude
can be approximately 45° with respect to the longitudinal axis. Acquiring signals
can include acquiring voltage signals with respect to tool orientation, the tool
orientation including a number of directions, the total number of directions
corresponding to one complete rotation partitioned into N bins, each bin associated
with an angle of rotation equal to 2p/N, N being an integer equal to or greater than
one. Acquiring signals can include acquiring voltage signals generated from
operating the tool rotating in the borehole. Acquiring signals generated from
operating the tool can include using a tool having an arrangement of one or more
transmitting sensors tilted substantially with respect to a longitudinal axis of the tool
and one or more receiving sensors tilted substantially with respect to the
longitudinal axis such that the acquired signals provide decoupled coupling
components.
At 1620, the acquired signals are processed in a processing unit, generating a
geosignal including a representation of a determination of variation between a XX
coupling component and a YY coupling component. The variation the XX coupling
component and the YY coupling component may be used to resolve ambiguities
associated with conventional tools in layered formations. Processing the acquired
signals can include decoupling coupling components from the acquired signals and
using the decoupled coupling components to generate the geosignal. Generating the
geosignal can include basing the geosignal on a difference between XX and YY
coupling component, a ratio between XX and YY coupling component, or a square
root of XX and YY coupling components. Generating the geosignal can include
basing the geosignal on a combination of coupling components according to
relationships of coupling components including (XX-YY)/(XX+YY+2ZZ), (XXYY)/(
XX+YY-2ZZ), XX/ZZ and YY/ZZ, (XX-YY)/ZZ and (XX+YY)/ZZ,
XX/(XX+YY+2ZZ) and YY/(XX+YY+2ZZ), or XX/(XX+YY-2ZZ) and
YY/(XX+YY-2ZZ). A geosignal can be generated from acquired compensated
signals. Generating a geosignal from the acquired signals includes generating a
geosignal phase and a geosignal attenuation. Processing the acquired signals can
include calculating coupling components for a coupling matrix using the acquired
signals, and performing one or more inversion operations to generate formation
parameters from the coupling matrix.
At 1630, a drilling-related operation is directed using the geosignal. The
drilling-related operation can include geosteering a drilling operation based on the
geosignal. The drilling-related operation can include performing analysis of the
formation structure using generated geosignals.
In various embodiments, a machine-readable storage device can comprise
instructions stored thereon, which, when performed by a machine, cause the
machine to perform operations, the operations comprising one or more features
similar to or identical to features of methods or techniques described herein. In
various embodiments, a system can comprise a tool having a longitudinal axis, the
tool including one or more transmitting sensors tilted with respect to the
longitudinal axis and one or more receiving sensors tilted with respect to the
longitudinal axis; and a processing unit to generate a geosignal based on a XX
coupling component, a YY coupling component, or a combination of XX coupling
component and YY coupling component, wherein the tool and the processing unit
are configured to operate according to one or more features similar to or identical to
features of methods or techniques described herein.
Currently, commercial geosteering tool services may not be able to make
any useful measurement when they are close to the center of a reservoir. For
instance, in a geosteering application using a conventional azimuthal directional EM
tool, the tool becomes blind to adjacent boundaries when it is located near the center
of the layer. Therefore, directional guidance on the basis of such a tool becomes
useless under this circumstance. Herein, embodiments of geosignal methodologies
can resolve this and similar ambiguity issues. Such geosignal responses when used
along with known geosignal responses can assist petrophysicists to acquire more
accurate formation geology and more reliably steer the tool in real-time. Increased
geosteering reliability may be made attained using embodiments of geosignal
responses, similar to or identical to geosignal responses taught herein, only are
available when both transmitter and receiver are tilted.
Figure 17 depicts a block diagram of features of an example system 1700
operable to conduct a drilling-related activity with respect to a geosignal. The
system 1700 includes a tool 1705 having an arrangement of transmitter antenna(s)
1710-1 and receiver antenna(s) 1710-2 operable in a borehole. The arrangements of
the transmitter antenna(s) 1710-land the receiver antenna(s) 1710-2 of the tool 1705
can be realized similar to or identical to arrangements discussed herein. The system
1700 can also include a controller 1720, a memory 1740, an electronic apparatus
1750, and a communications unit 1735. The controller 1720 and the memory 1740
can be arranged to operate the tool 1705 to acquire measurement data as the tool
1705 is operated and to assign the acquired data to a number of bins, each correlated
to an azimuthal angle in a rotation of the tool 1705. The controller 1720 and the
memory 1740 can be realized to control activation of selected ones of the
transmitter antennas 1710-1 and data acquisition by selected one of the receiver
antennas 1710-2 in the tool 1705 and to manage processing schemes to determine a
geosignal in accordance with measurement procedures and signal processing as
described herein. Processing unit 1720 can be structured to perform the operations
to manage processing schemes to determine a geosignal in accordance with
measurement procedures and signal processing in a manner similar to or identical to
embodiments described herein.
Electronic apparatus 1750 can be used in conjunction with the controller
1720 to perform tasks associated with taking measurements downhole with the
transmitter antenna(s) 1710-1 and the receiver antenna(s) 1710-2 of the tool 1705.
The communications unit 1735 can include downhole communications in a drilling
operation. Such downhole communications can include a telemetry system.
The system 1700 can also include a bus 1747, where the bus 1747 provides
electrical conductivity among the components of the system 1700. The bus 1747
can include an address bus, a data bus, and a control bus, each independently
configured. The bus 1747 can also use common conductive lines for providing one
or more of address, data, or control, the use of which can be regulated by the
controller 1720. The bus 1747 can be configured such that the components of the
system 1700 are distributed. Such distribution can be arranged between downhole
components such as the transmitter antenna(s) 1710-1 and the receiver antenna(s)
1710-2 of the tool 1705 and components that can be disposed on the surface of a
well. Alternatively, the components can be co-located such as on one or more
collars of a drill string or on a wireline structure.
In various embodiments, peripheral devices 1760 can include displays,
additional storage memory, and/or other control devices that may operate in
conjunction with the controller 1720 and/or the memory 1740. In an embodiment,
the controller 1720 can be realized as one or more processors. The peripheral
devices 1760 can be arranged with a display with instructions stored in the memory
1740 to implement a user interface to manage the operation of the tool 1705 and/or
components distributed within the system 1700. Such a user interface can be
operated in conjunction with the communications unit 1735 and the bus 1747.
Various components of the system 1700 can be integrated with the tool 1705 such
that processing identical to or similar to the processing schemes discussed with
respect to various embodiments herein can be performed downhole in the vicinity of
the measurement or at the surface.
Figure 18 depicts an embodiment of a system 1800 at a drilling site, where
the system 1800 includes an apparatus operable to conduct a drilling-related activity
with respect to a geosignal. The system 1800 can include a tool 1805-1, 1805-2, or
both 1805-1 and 1805-2 having an arrangement of transmitter antennas and receiver
antennas operable to make measurements that can be used for a number of drilling
tasks including, but not limited to, determining geosignals. The tools 1805-1 and
1805-2 can be structured identical to or similar to a tool architecture or
combinations of tool architectures discussed herein, including control units and
processing units operable to perform processing schemes in a manner identical to or
similar to processing techniques to determine geosignals discussed herein. The
tools 1805-1, 1805-2, or both 1805-1 and 1805-2 can be distributed among the
components of system 1800. The tools 1805-1 and 1805-2 can be realized in a
similar or identical manner to arrangements of control units, transmitters, receivers,
and processing units discussed herein. The tools 1805-1 and 1805-2 can be
structured, fabricated, and calibrated in accordance with various embodiments as
taught herein.
The system 1800 can include a drilling rig 1802 located at a surface 1804 of
a well 1806 and a string of drill pipes, that is, drill string 1829, connected together
so as to form a drilling string that is lowered through a rotary table 1807 into a
wellbore or borehole 1812-1. The drilling rig 1802 can provide support for the drill
string 1829. The drill string 1829 can operate to penetrate rotary table 1807 for
drilling the borehole 1812-1 through subsurface formations 1814. The drill string
1829 can include a drill pipe 1818 and a bottom hole assembly 1820 located at the
lower portion of the drill pipe 1818.
The bottom hole assembly 1820 can include a drill collar 1816 and a drill bit
1826. The drill bit 1826 can operate to create the borehole 1812-1 by penetrating
the surface 1804 and the subsurface formations 1814. The bottom hole assembly
1820 can include the tool 1805-1 attached to the drill collar 1816 to conduct
measurements to determine formation parameters. The tool 1805-1 can be
structured for an implementation as a MWD system such as a LWD system. The
housing containing the tool 1805-1 can include electronics to initiate measurements
from selected transmitter antennas and to collect measurement signals from selected
receiver antennas. Such electronics can include a processing unit to provide
analysis of formation parameters and geosignals over a standard communication
mechanism for operating in a well. Alternatively, electronics can include a
communications interface to provide measurement signals collected by the tool
1805-1 to the surface over a standard communication mechanism for operating in a
well, where these measurements signals can be analyzed at a processing unit at the
surface to provide analysis of formation parameters and to determine geosignals.
During drilling operations, the drill string 1829 can be rotated by the rotary
table 1807. In addition to, or alternatively, the bottom hole assembly 1820 can also
be rotated by a motor (e.g., a mud motor) that is located downhole. The drill collars
1816 can be used to add weight to the drill bit 1826. The drill collars 1816 also can
stiffen the bottom hole assembly 1820 to allow the bottom hole assembly 1820 to
transfer the added weight to the drill bit 1826, and in turn, assist the drill bit 1826 in
penetrating the surface 1804 and the subsurface formations 1814.
During drilling operations, a mud pump 1832 can pump drilling fluid
(sometimes known by those of skill in the art as "drilling mud") from a mud pit
1834 through a hose 1836 into the drill pipe 1818 and down to the drill bit 1826.
The drilling fluid can flow out from the drill bit 1826 and be returned to the surface
1804 through an annular area 1840 between the drill pipe 1818 and the sides of the
borehole 1812-1. The drilling fluid may then be returned to the mud pit 1834,
where such fluid is filtered. In some embodiments, the drilling fluid can be used to
cool the drill bit 1826, as well as to provide lubrication for the drill bit 1826 during
drilling operations. Additionally, the drilling fluid may be used to remove
subsurface formation cuttings created by operating the drill bit 1826.
In various embodiments, the tool 1805-2 may be included in a tool body
1870 coupled to a logging cable 1874 such as, for example, for wireline
applications. The tool body 1870 containing the tool 1805-2 can include electronics
to initiate measurements from selected transmitter antennas and to collect
measurement signals from selected receiver antennas. Such electronics can include
a processing unit to provide analysis of formation parameters and geosignals over a
standard communication mechanism for operating in a well. Alternatively,
electronics can include a communications interface to provide measurement signals
collected by the tool 1805-2 to the surface over a standard communication
mechanism for operating in a well, where these measurements signals can be
analyzed at a processing unit at the surface to provide analysis of formation
parameters, including an estimate of the true formation resistivity for each formation
layer investigated. The logging cable 1874 may be realized as a wireline (multiple
power and communication lines), a mono-cable (a single conductor), and/or a slickline
(no conductors for power or communications), or other appropriate structure for
use in the borehole 1812. Though Figure 18 depicts both an arrangement for
wireline applications and an arrangement for LWD applications, the system 1800
may be also realized for one of the two applications.
In various embodiments, a measurement tool and processing unit can be
arranged to determine and generate XX and YY coupling components that include
sensitivity of both XX and YY coupling components to differentiate between null
signals associated with conventional tools in a "blind-spot" and in homogeneous
medium. The sensitivity of XX and YY coupling components may be provided by
processing to decouple coupling components of a coupling matrix, by arrangement
of transmitting sensors and receiving sensors that that directly provides decoupled
XX and YY coupling components, and by arrangement of transmitting sensors and
receiving sensors that that provides decoupled XX and YY coupling components
with limited processing. Different geosignals can be generated according to
different combinations of coupling components that utilize XX and YY sensitivity
to resolve "blind- spot" issues.
Although specific embodiments have been illustrated and described herein, it
will be appreciated by those of ordinary skill in the art that any arrangement that is
calculated to achieve the same purpose may be substituted for the specific
embodiments shown. Various embodiments use permutations and/or combinations
of embodiments described herein. It is to be understood that the above description
is intended to be illustrative, and not restrictive, and that the phraseology or
terminology employed herein is for the purpose of description. Combinations of the
above embodiments and other embodiments will be apparent to those of skill in the
art upon studying the above description.

CLAIMS
What is claimed is:
1. A method comprising:
acquiring signals generated from operating a tool in a borehole;
processing the acquired signals in a processing unit;
generating a geosignal including a representation of a determination of
variation between a XX coupling component and a YY coupling component; and
directing a drilling-related operation using the geosignal.
2. The method of claim 1, wherein processing the acquired signals includes
decoupling coupling components from the acquired signals and using the decoupled
coupling components to generate the geosignal.
3. The method of claim 1, wherein acquiring signals generated from operating
the tool includes using a tool having an arrangement of one or more transmitting
sensors tilted substantially with respect to a longitudinal axis of the tool and one or
more receiving sensors tilted substantially with respect to the longitudinal axis such
that the acquired signals provide decoupled coupling components.
4. The method of claim 1, wherein generating the geosignal includes basing the
geosignal on a difference between XX and YY coupling component, a ratio between
XX and YY coupling component, or a square root of XX and YY coupling
components.
5. The method of claim 1, wherein generating the geosignal includes basing the
geosignal on a combination of coupling components related to
(XX-YY)/(XX+YY+2ZZ), (XX-YY)/(XX+YY-2ZZ), XX/ZZ and YY/ZZ, (XXYY)/
ZZ and (XX+YY)/ZZ, XX/(XX+YY+2ZZ) and YY/(XX+YY+2ZZ), or
XX/(XX+YY-2ZZ) and YY/(XX+YY-2ZZ).
6. The method of claim 1, wherein acquiring signals includes acquiring
compensated signals, and wherein the geosignal is generated from the compensated
signals.
7. The method of claim 1, wherein acquiring signals generated from operating
the tool includes using a tool having one or more transmitting sensors tilted
substantially with respect to a longitudinal axis of the tool and one or more
receiving sensors tilted substantially with respect to the longitudinal axis, the
acquired signals including signals received at the one or more tilted receiving
sensors in response to generating a transmission signal from each of the one or more
tilted transmitting sensors.
8. The method of claim 7, wherein acquiring signals includes acquiring voltage
signals generated from operating the tool to selectively activate selected transmitting
sensors of the one or more tilted transmitting sensors and to selectively collect the
signals from selected tilted receiving sensors of the one or more tilted receiving
sensors such that the selected transmitting sensors and the selected tilted receiving
sensors are in a symmetric arrangement with respect to the longitudinal axis.
9. The method of claim 7, wherein the one or more transmitting sensors and the
one or more receiving sensors are antennas tilted with tilt angle having a magnitude
of 45° or within one or two degrees of 45° with respect to the longitudinal axis.
10. The method of claim 1, wherein processing the acquired signals includes:
calculating coupling components for a coupling matrix using the acquired
signals; and
performing one or more inversion operations to generate formation
parameters from the coupling matrix.
11. The method of claim 1, wherein acquiring signals includes acquiring voltage
signals with respect to tool orientation, the tool orientation including a number of
directions, the total number of directions corresponding to one complete rotation
partitioned into N bins, each bin associated with an angle of rotation equal to 2p/N,
N being an integer equal to or greater than one.
12. The method of claim 1, wherein acquiring signals includes acquiring voltage
signals generated from operating the tool rotating in the borehole.
13. The method of claim 1, wherein the method includes geosteering a drilling
operation based on the geosignal.
14. The method of claim 1, wherein determining a geosignal from the acquired
signals includes generating a geosignal phase and a geosignal attenuation.
15. A machine-readable storage device having instructions stored thereon,
which, when performed by a machine, cause the machine to perform operations, the
operations comprising the method of any of claims 1 to 14.
16. A system comprising:
a tool having one or more transmitting sensors and one or more receiving
sensors; and
a processing unit to generate a geosignal including a representation of a
determination of variation between a XX coupling component and a YY coupling
component, wherein the tool and the processing unit are configured to operate
according to any of claims 1 to 14.