FRACTURE DETECTION AND CHARACTERIZATION USING
RESISTIVITY IMAGES
BACKGROUND
The present disclosure relates generally to well drilling operations and, more
particularly, to fracture detection and characterization using resistivity images.
Hydrocarbons, such as oil and gas, are commonly obtained from subterranean
formations that may be located onshore or offshore. The development of subterranean
operations and the processes involved in removing hydrocarbons from a subterranean formation
are complex. Typically, subterranean operations involve a number of different steps such as, for
example, drilling a wellbore at a desired well site, treating the wellbore to optimize production of
hydrocarbons, and performing the necessary steps to produce and process the hydrocarbons from
the subterranean formation.
Measurements of the subterranean formation may be made throughout the
operations to characterize the formation and aide in making operational decisions. One example
measurement corresponds to the electrical resistivity (or its inverse conductivity) of the
formation, which can be used to determine whether the formation or a layer of the formation is
likely to contain hydrocarbons. Natural fractures or cracks within the formation may skew the
measurements, however, reducing the accuracy of the calculated resistivity and the decisions
made based on the calculated resistivity.
FIGURES
Some specific exemplary embodiments of the disclosure may be understood by
referring, in part, to the following description and the accompanying drawings.
Figure 1 is a diagram showing an illustrative logging while drilling environment,
according to aspects of the present disclosure.
Figure 2 is a diagram showing an illustrative wireline logging environment,
according to aspects of the present disclosure.
Figure 3 is a diagram of an example information handling system, according to
aspects of the present disclosure.
Figure 4 is a diagram of an example resistivity logging tool, according to aspects
of the present disclosure.
Figure 5 is a diagram of an example control system for a resistivity logging tool,
according to aspects of the present disclosure.
Figure 6 is a diagram of example azimuthal bins for measurements taken using a
resistivity logging tool, according to aspects of the present disclosure.
Figure 7 is a diagram of a model of an example resistivity logging tool in a
formation with at least one fracture, according to aspects of the present disclosure.
Figure 8 are graphs illustrating example propagation resistivity images, according
to aspects of the present disclosure.
Figure 9 are graphs illustrating example propagation resistivity images, according
to aspects of the present disclosure.
Figure 10 is a graph illustrating phase resistivity values, according to aspects of
the present disclosure.
Figure 11 is a graph illustrating phase resistivity values, according to aspects of
the present disclosure.
Figure 1 is a graph illustrating the azimuthal response of two bins of a resistivity
logging apparatus to a resistive fracture in a conductive formation, according to aspects of the
present disclosure.
Figure 13 is a graph illustrating an example azimuthal resistivity response,
according to aspects of the present disclosure.
Figure 14 illustrates graphs showing example reoriented propagation resistivity
images of fractures, according to aspects of the present disclosure.
Figure 15 is flow diagram illustrating an example process, according to aspects of
the present disclosure.
While embodiments of this disclosure have been depicted and described and are
defined by reference to exemplary embodiments of the disclosure, such references do not imply a
limitation on the disclosure, and no such limitation is to be inferred. The subject matter
disclosed is capable of considerable modification, alteration, and equivalents in form and
function, as will occur to those skilled in the pertinent art and having the benefit of this
disclosure. The depicted and described embodiments of this disclosure are examples only, and
not exhaustive of the scope of the disclosure.
DETAILED DESCRIPTION
For purposes of this disclosure, an information handling system may include any
instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit,
receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or
utilize any form of information, intelligence, or data for business, scientific, control, or other
purposes. For example, an information handling system may be a personal computer, a network
storage device, or any other suitable device and may vary in size, shape, performance,
functionality, and price. The information handling system may include random access
memory (RAM), one or more processing resources such as a central processing unit (CPU) or
hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional
components of the information handling system may include one or more disk drives, one or
more network ports for communication with external devices as well as various input and
output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling
system may also include one or more buses operable to transmit communications between the
various hardware components. It may also include one or more interface units capable of
transmitting one or more signals to a controller, actuator, or like device.
For the purposes of this disclosure, computer-readable media may include any
instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a
period of time. Computer-readable media may include, for example, without limitation, storage
media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a
sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM,
ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory;
as well as communications media such wires, optical fibers, microwaves, radio waves, and other
electromagnetic and/or optical carriers; and/or any combination of the foregoing.
Illustrative embodiments of the present disclosure are described in detail herein.
In the interest of clarity, not all features of an actual implementation may be described in this
specification. It will of course be appreciated that in the development of any such actual
embodiment, numerous implementation-specific decisions are made to achieve the specific
implementation goals, which will vary from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and time-consuming, but would,
nevertheless, be a routine undertaking for those of ordinary skill in the art having the benefit of
the present disclosure.
To facilitate a better understanding of the present disclosure, the following
examples of certain embodiments are given. In no way should the following examples be read to
limit, or define, the scope of the invention. Embodiments of the present disclosure may be
applicable to horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type of
subterranean formation. Embodiments may be applicable to injection wells as well as
production wells, including hydrocarbon wells. Embodiments may be implemented using a tool
that is made suitable for testing, retrieval and sampling along sections of the formation.
Embodiments may be implemented with tools that, for example, may be conveyed through a
flow passage in tubular string or using a wireline, slickline, coiled tubing, downhole robot or the
like. "Measurement-while-drilling" ("MWD") is the term generally used for measuring
conditions downhole concerning the movement and location of the drilling assembly while the
drilling continues. "Logging- while-drilling" ("LWD") is the term generally used for similar
techniques that concentrate more on formation parameter measurement. Devices and methods in
accordance with certain embodiments may be used in one or more of wireline (including
wireline, slickline, and coiled tubing), downhole robot, MWD, and LWD operations.
The terms "couple" or "couples" as used herein are intended to mean either an
indirect or a direct connection. Thus, if a first device couples to a second device, that connection
may be through a direct connection or through an indirect mechanical or electrical connection
via other devices and connections. Similarly, the term "communicatively coupled" as used herein
is intended to mean either a direct or an indirect communication connection. Such connection
may be a wired or wireless connection such as, for example, Ethernet or LAN. Such wired and
wireless connections are well known to those of ordinary skill in the art and will therefore not be
discussed in detail herein. Thus, if a first device communicatively couples to a second device,
that connection may be through a direct connection, or through an indirect communication
connection via other devices and connections.
Figure 1 is a diagram of a subterranean drilling system 100, according to aspects
of the present disclosure. The drilling system 100 comprises a drilling platform 2 positioned at
the surface 102. In the embodiment shown, the surface 102 comprises the top of a formation 104
containing one or more rock strata or layers 18a-c, and the drilling platform 2 may be in contact
with the surface 102. In other embodiments, such as in an off-shore drilling operation, the
surface 102 may be separated from the drilling platform 2 by a volume of water.
The drilling system 100 comprises a derrick 4 supported by the drilling platform 2
and having a traveling block 6 for raising and lowering a drill string 8. A kelly 10 may support
the drill string 8 as it is lowered through a rotary table 12. A drill bit 14 may be coupled to the
drill string 8 and driven by a downhole motor and/or rotation of the drill string 8 by the rotary
table 12. As bit 14 rotates, it creates a borehole 6 that passes through one or more rock strata or
layers 18. A pump 20 may circulate drilling fluid through a feed pipe 22 to kelly 10, downhole
through the interior of drill string 8, through orifices in drill bit 14, back to the surface via the
annulus around drill string 8, and into a retention pit 24. The drilling fluid transports cuttings
from the borehole 16 into the pit 24 and aids in maintaining integrity or the borehole 16.
The drilling system 100 may comprise a bottom hole assembly (BHA) coupled to
the drill string 8 near the drill bit 14. The BHA may comprise various downhole measurement
tools and sensors and LWD and MWD elements, including a resistivity logging tool 26. The
resistivity logging tool 26 may comprise a plurality of transmitters and receivers (e.g., antennas
capable of receiving and/or transmitting one or more electromagnetic signals) such as magnetic
dipoles that are axially spaced along the length of the tool and positioned at different angles with
respect to the tool 26. As the bit extends the borehole 16 through the formations 18, the
resistivity logging tool 26 may collect measurements relating to the resistivity of the formation
104, i.e., how strongly the formation 104 opposes a flow of electric current. In certain
embodiments, the orientation and position of the tool 26 may be tracked using, for example, an
azimuthal orientation indicator, which may include magnetometers, inclinometers, and/or
accelerometers, though other sensor types such as gyroscopes may be used in some embodiments. In
embodiments including an azimuthal orientation indicator, the resistivity measurements may be
associated with a particular azimuthal orientation through azimuthal binning, as will be described
below.
The tools and sensors of the BHA including the resistivity logging tool 26 may be
communicably coupled to a telemetry element 28. The telemetry element 28 may transfer
measurements from the resistivity logging tool 26 to a surface receiver 30 and/or to receive
commands from the surface receiver 30. The telemetry element 28 may comprise a mud pulse
telemetry system, and acoustic telemetry system, a wired communications system, a wireless
communications system, or any other type of communications system that would be appreciated by
one of ordinary skill in the art in view of this disclosure. In certain embodiments, some or all of the
measurements taken at the resistivity logging tool 26 may also be stored within the tool 26 or the
telemetry element 28 for later retrieval at the surface 102.
In certain embodiments, the drilling system 100 may comprise an information
handling system 32 positioned at the surface 102. The information handling system 32 may be
communicably coupled to the surface receiver 30 and may receive measurements from the
resistivity logging tool 26 and/or transmit commands to the resistivity logging tool 26 though the
surface receiver 30. The information handling system 32 may also receive measurements from
the resistivity logging tool 26 when the tool 26 is retrieved at the surface 102. As will be
described below, the information handling system 32 may process the measurements to
determine certain characteristics of the formation 104, including the location and characteristics
of fractures within the formation 104.
At various times during the drilling process, the drill string 8 may be removed
from the borehole 16 as shown in Figure 2. Once the drill string 8 has been removed,
measurement/logging operations can be conducted using a wireline tool 34, i.e., an instrument
that is suspended into the borehole 16 by a cable 15 having conductors for transporting power to
the tool and telemetry from the tool body to the surface 102. The wireline tool 34 may include a
resistivity logging tool 36 having transmitters and receivers similar to those described above in
relation to the resistivity logging tool 26. The resistivity logging tool 36 may be
communicatively coupled to the cable 15. A logging facility 44 (shown in Figure 2 as a truck,
although it may be any other structure) may collect measurements from the resistivity logging
tool 36, and may include computing facilities (including, e.g., an information handling system)
for controlling, processing, storing, and/or visualizing the measurements gathered by the
resistivity logging tool 36. The computing facilities may be communicatively coupled to the
logging/measurement tool 36 by way of the cable 15. In certain embodiments, the information
handling system 32 may serve as the computing facilities of the logging facility 44.
As described above, Figs. 1 and 2 show a formation 104 one or more rock strata
or layers 18a-c. Each of the strata 18a-c may have different physical and electrical
characteristics. For example, some of the strata may be generally conductive while others may
be generally resistive. Likewise, some may be generally porous while some may be non-porous.
In certain instances, natural fractures or cracks may be located within strata 18a-c. In Figs. 1 and
2, the borehole 16 intersects a fracture 106 in layer 18b. Fracture 106 may have different
characteristics than the rock layer in which it is located, and the different characteristics may
skew the measurements of the strata. For example, layer 1 b may comprise a resistive layer, yet
fracture 106 may contain conductive fluids, or layer 18b may comprise a conductive layer, yet
fracture 106 may contain resistive fluids. Identifying, characterizing, and accounting for these
fractures may, therefore, improve the resulting measurements of the formation 04 generally and
the strata 18a-c in particular.
Figure 3 is a block diagram showing an example information handling system
300, according to aspects of the present disclosure. Information handling system 300 may be
used with the drilling system described above. The information handling system 300 may
comprise a processor or CPU 301 that is communicatively coupled to a memory controller hub
or north bridge 302. Memory controller hub 302 may include a memory controller for directing
information to or from various system memory components within the information handling
system, such as RAM 303, storage element 306, and hard drive 307. The memory controller hub
302 may be coupled to RAM 303 and a graphics processing unit 304. Memory controller hub
302 may also be coupled to an I/O controller hub or south bridge 305. I/O hub 305 is coupled to
storage elements of the computer system, including a storage element 306, which may comprise
a flash ROM that includes a basic input/output system (BIOS) of the computer system. I/O hub
305 is also coupled to the hard drive 307 of the computer system. I/O hub 305 may also be
coupled to a Super I/O chip 308, which is itself coupled to several of the I/O ports of the
computer system, including keyboard 309 and mouse 310. The information handling system 300
further may be communicably coupled to one or more elements of a drilling system though the
chip 308 as well as a visualization mechanism, such as a computer monitor or display.
The information handling system(s) used in the subterranean drilling systems
described above may include software components that process and characterize data. As used
herein, software or software components may comprise a set of instructions stored within a
computer readable medium that, when executed by a processor coupled to the computer readable
medium, cause the processor to perform certain actions. According to aspects of the present
disclosure, the actions may be performed with respect to measurements from a resistivity logging
tool to identify and characterize fractures within a formation.
Figures 4A and 4B illustrate example resistivity logging tools, according to
aspects of the present disclosure. Fig. 4A shows a resistivity logging tool 400 that may be used
as an LWD/MWD tool or within a wireline arrangement, described above, and may comprise at
least one magnetic dipole transmitter and at least one magnetic dipole receiver. In the
embodiment shown, the tool 400 comprises transmitters T1-T3 and Ti' -T3' and receivers R1-R3
axially spaced along the length of the tool 400. The transmitters T 1-T3 and Ti' -T3' may be
coaxial, as shown, and/or tilted with respect to a tool body 410. The receivers R1-R3 may be
tilted and axially spaced apart from the transmitters T 1-T3 and T ' -T3' and from each other with
respect to the tool body 410. Because the receivers R R3 may be tilted, measurements taken
with them may be azimuthally sensitive. In certain embodiments, the transmitters T1-T3 and T -
T3' and receivers Rj-R 3 may comprise dipole antennas that may be mounted in recesses in the
tool body 410 and protected by a non-conductive material or a material with non-conducting
apertures.
In the embodiment shown, the transmitters T1-T3 and Ti' -T3' comprise symmetric
coaxial transmitter antennas T 1-T1' , T2-T2' , and T3-T3' spaced at 16-inch increments from a
center 420 of the two receivers Rj and R2. Specifically, the transmitters T3-T3' each may be
located 16 inches from the center 420, the transmitters T2-T ' each may be located 32 inches
from the center 420, and the transmitters T i-Ί each may be located at 48 inches from the center
420. Receivers R and R may be spaced four inches from each other and tilted at a 45 degree
angle with respect to a longitudinal axis of the tool body 410. And receiver R3 may be located
64 inches from the center 420.
As can be seen in Fig. 4B, other configurations for the transmitters and receiver
are possible, including the number, spacing, orientation, angle, etc. Specifically, tools 450-460
illustrate tools with different orientations of receivers and R2 and transmitters Ti and . For
example, the transmitters and receivers may be parallel, perpendicular, and/or co-located with
each other. Additionally, either or both of the receivers Ri and R2 and transmitters T \ and
may be tilted with respect to the axis of the tool. Notably, the distance between a transmitter and
a receiver is positively correlated with the range of measurement and negatively correlated with
the measurement resolution. Accordingly, having transmitters and receivers located at various
distances balances the range and resolution of the tool, with the particular distances chosen based
on characteristics of the formation in which the tool will be introduced.
Figure 5 is a diagram of an example control system 500 for a resistivity logging
tool, according to aspects of the present disclosure. The system 500 comprises a system control
center 502 that may function as the primary controller for the tool. In certain embodiments, the
system control center 302 may comprise an information handling system, and may be
communicably coupled to transmitters 1-N through transmitter electronics 504 and
communicably coupled to receivers 1-M through receiver electronics 506. The transmitters 1-N
and receivers 1-M may comprise coaxial or tilted magnetic dipoles, similar to those described
above with reference to Fig. 4. The transmitter electronics 504 and receiver electronics 506 may
comprise circuit boards to which some or all of the transmitters 1-N and receivers 1-M are
coupled.
The system control center 502 may trigger the transmitter electronics 504 to
generate a time-varying electromagnetic (EM) signal through one or more of the transmitters 1-
N. The transmitter electronics 504 may trigger each of the transmitters 1-N independently,
selecting a transmitter based on the transmitter's orientation (e.g., distance) with respect to the
receivers. The time-varying EM signal may be a sinusoidal signal, its phase, amplitude, and
frequency set at a desired value. In certain embodiment, the system control center 502 may
cause one transmitter to transmit multiple time-varying EM signals, each with a different phase,
amplitude, and/or frequency. In certain embodiments, the system control center 502 may cause
each of the transmitters 1-N to transmit a different time-varying EM signal, with different
phases, amplitudes, and/or frequencies. Other transmission schemes are possible, as would be
appreciated by one of ordinary skill in the art in view of this disclosure.
The time-varying EM signals generated by one or more of the transmitters 1-N
may excite the formation surrounding the tool, and one or more of the receivers 1-M may
measure the response of the formation to the time-varying EM signals. In certain embodiments,
one or more of the receivers 1-M may be tuned to measure a response within a frequency band
containing the transmitted time-varying EM signal. The system control center 502 may receive
the measured responses from the receivers 1-M through the receiver electronics 506 and may
transmit the measured responses to the data acquisition unit 508. For a specific transmitter
excitation, measured responses from multiple receivers can be received at the same time.
Similarly, multiple transmitters 1-N can be excited at the same time and they can be time,
frequency or jointly multiplexed for latter demultiplexing operation at the receivers. Upon
reception at the data acquisition unit 508, the measured responses may be digitized, stored in a
data buffer 510, processed at data processing unit 512, and sent to the surface 514 through a
communication unit 316, which may comprise a downhole telemetry system.
In certain embodiments, the responses from the receivers 1-M may be measured
with respect to the signals from the transmitters 1-N that generated the responses. In certain
embodiments, this may include comparing the measured responses to the transmitters signals.
The comparison may be made, for example, downhole in the data processing unit 512, or at an
information handling system at the surface. When the comparison is made downhole, the system
control unit 502 may communicate the phase, amplitude, and frequency of the transmitted timevarying
EM signals to the data processing unit 512, which may compare the time-varying EM
signals to the measured responses from the receivers 1-M. In certain embodiments, the data
processing unit 512 may determine the phase and amplitude of the measured responses, and
compare the determined phase and amplitude of the measured responses to the phase and
amplitude of the corresponding transmitted time-varying EM signal. Accordingly, the amplitude
of the measured response may comprise an amplitude ratio or amplitude difference with respect
to the transmitted time-varying EM signal, and the phase of the measured response may
comprise a phase shift or difference with respect to the transmitted time-varying EM signal. As
will be described below, the phase and amplitude of the measured responses may be used to
identify and characterize fractures within the formation surrounding the tool.
Resistivity logging tools similar to those described above may be azimuthally
sensitive based on the azimuthal orientation of the tilted receiver and/or transmitter. At a given
time, the azimuthal direction in which the tool is directed may be referred to as the tool face
angle. The tool face angle may be identified, for example, using orientation sensors described
above. When a resistivity logging tool is placed within a borehole and rotated (e.g., during
drilling operations in a LWD/MWD configuration), azimuthally sensitive measured responses of
the formation surrounding the tool may be made, with the azimuthal direction of each measured
response being associated with the tool face angle of the logging tool when the response was
measured. If the tool is rotated at one depth, for example, measured responses along 360 degrees
of rotation may be collected.
In certain embodiment, the measured responses may be divided into a plurality of
azimuthal "bins" according to the tool face angle associated within the measured responses. Fig.
6 is a diagram of example bins, according to aspects of the present disclosure. Each "bin" may
correspond to a range of tool face angles for the resistivity logging tool, with each bin range
equal to 360/M and M equal to the number of bins. In the embodiment shown, there are 32 total
bins, each corresponding to 11.25 degrees of the formation surrounding the tool. Each bin may
comprise amplitudes and phases for measured responses captured when the tool face was
oriented within the corresponding angular range. For example, the arrow 602 may identify the
current tool face angle for a tool and the bin (bin 3) in which measured responses taken at that
tool face angle will be stored. The bins may be numbered to identify the bins with respect to one
another. In the embodiment shown, bin 1 corresponds to a zero degree tool face angle,
perpendicular to the axis of the tool, with bin 17 corresponding to a 180 degree tool face angle,
opposite bin . In certain embodiments, as will also be described below, the bin numbering may
be changed to reduce the computational burden of identifying and characterizing a formation
fracture.
In certain embodiments, measurements for each of the bins may be calculated
based on the measured response of the formation in one azimuthal orientation. Although the
tilted magnetic dipoles have the greatest azimuthal sensitivity in one azimuthal direction, the
tilted magnetic dipole may also collect responses regarding the formation in other azimuthal
directions. According to aspects of the present disclosure, the formation response measured by a
magnetic dipole in a first azimuthal direction may be processed, and the response contributions
from the formation in other azimuthal angles may be extracted, adjusted, and segregated into
azimuthal bins, similar to those described above.
According to aspects of the present disclosure, the amplitudes and phases of the
responses associated with each bin may be processed to determine resistivity values for each bin.
As described above, a resistivity logging tool may comprise at least one transmitter and at
least two receivers R and R2, with time-varying EM signals transmitted by the transmitter Ti
causing formation responses to be measured at receivers R and R along the tool. The timevarying
EM signals transmitted by transmitter Ti and the measured responses at the receivers R
and R2 may be characterized by amplitude and phase values. In certain embodiments, the
difference in amplitude and phase between the measured responses at Ri and R2 to a signal
generated by the transmitter T may be calculated using Equations (1) and (2)
Equation (1): AA (k) = 201og( i (*)) - 20 \ g{AR (k))
Equation (2): Af (k) =fi (k) - f (k)
where A * comprises amplitude, f * comprises phase, R * comprises a receiver, T* comprises a
transmitter, and k comprises the bin number. In particular, A k) comprises the amplitude of
the measured response from receiver Ri to a signal generated by the source T at the k h bin
position; AR (k) comprises the amplitude of the measured response from receiver R2 to a signal
generated by the source Tj at the kth bin position; R (k) comprises the phase of the measured
response from receiver Ri to a signal generated by the source Ti at the kt bin position; and
( ) comprises the phase of the measured response from receiver Ri to a signal generated by
the source at the kth bin position. A resistivity value for the bin may be calculated using a
look-up table or an inversion algorithm and the values calculated using equations (1) and (2).
In certain embodiments, processing the measured responses may further comprise
calculating at least one of a compensated signal for the bins using the phase shift and attenuation
information, and using the calculated compensated signal to calculate a resistivity value for each
bin. In addition to the amplitude and phase values calculated for transmitter similar
amplitude and phase values corresponding to a given bin may be calculated for the other
transmitters of a resistivity logging tool, some of which may form symmetric pairs, such as
transmitters Ί \ -Ύ , T2-T2' , and T3-T3' from Fig. 4. In certain embodiments, a compensated
signal may be generated by averaging together the responses for at least one symmetric pair of
transmitters. For example, when a resistivity logging tool comprises a symmetric pair of
transmitters Ti and Y, equations (1) and (2) may be used to calculate attenuation and phase
values for each of the transmitters (e.g., AA k ) , D ft ΐ ) , AA (k), and D f )), and the
attenuation and phase values may be averaged using the following equations to form
compensated attenuation and phase values:
Equation (3): AA (k) = ( i (k) +AA k ))l 2
Equation (4): Af ) = (Af ( +Af ) / 2
A resistivity value for the bin may be calculated using a look-up table or an inversion algorithm
and the values calculated using equations (3) and (4).
In certain embodiments, an averaged compensated value may be calculated by
averaging together the compensated values from at least two symmetric pairs of transmitters.
For example, assuming a resistivity logging tool comprises symmetric pairs T - and T2-T2' ,
equations (l)-(4) may be used to calculate attenuation and phase values and compensated values
for each transmitter and symmetric pair, respectively, and compensated values for the symmetric
pairs Ti-TY and T2-T2' may be averaged together. A look-up table or inversion algorithm may
also be used to calculate a resistivity value for the bin based on the averaged compensated value.
In another embodiment the resistivity values for each one of the bins may be
calculated using a look-up table or inversion algorithm and a geo-signal. As used herein, a geosignal
may be calculated by taking the difference between the phase or log amplitude for one bin
and the average phase or log amplitude for all of the bins at a given axial location. For example,
a geo-signal may be calculated for a receiver Ri and transmitter Ti using the following equations:
Equation (5): geo _att R k) =2 l g(AR (k))- ( 2) å 2 1 g(ARlTl (i))
i-\,m
Equation (6): geo _ phaR (k) =fi (k) - (1/ m) f h ( )
i~l ,
where geo* comprises a geosignal, att* comprises attenuation, *pha comprises phase, A*
comprises amplitude, f * comprises phase, R* comprises a receiver, T* comprises a transmitter,
and k comprises the bin number, and m comprises the total number of bins.
According to aspects of the present disclosure, the resistivity values calculated
above may be used to form induction or propagation resistivity images of a formation, which can
in turn be used to identify and characterize fractures within a formation. Fig. 7 is a diagram of
an example resistivity logging tool in a formation with at least one fracture, according to aspects
of the present disclosure. The tool 700 is positioned within the formation 710 along an axis 720
corresponding to the longitudinal axis of the tool 700. As described above, the tool 700 may
comprise a LWD/MWD tool or a wireline tool. The formation 710 comprises a fracture 730
through which the tool 700 is passing. The tool 700 may be oriented at a "dip angle" 740 with
respect to the fracture 730, corresponding to the angle between the axis 720 and the fracture 730.
The tool 700 may take at least one azimufhally sensitive formation response
measurement of the formation 710, which may be used to calculate resistivity values for the
formation 710, as described above. In certain embodiments, azimuthally sensitive formation
response measurements may be taken at more than one axial location along the axis 720,
corresponding to depths of the formation. For example, the azimuthally sensitive measurements
may be taken constantly, or near-constantly, to provide detailed 360 degree measurements of the
formation 710 at each depth encountered by the tool. In other embodiments, azimuthally and
axially limited measurements may be taken from which 360 degree measurements at multiple
depths may be calculated. As will be described below, the resistivity values calculated using the
measurements may change as the tool 700 nears the fracture 730, and the fracture 730 may be
identified and characterized based of the changing resistivity values.
The azimuthally and axially distinct resistivity values may be combined into an
induction or propagation resistivity image of the formation. Fig. 8 is a diagram illustrating
example propagation resistivity images 800 and 850. As can be seen, the images 800 and 850
comprise graphs that plot the resistivity values of the formation in terms of depth of the
formation in feet (y-axes) and azimuthal orientation by bin number (x-axes). Notably, each of
the images 800 and 850 comprises an Rp section and a Ra section, corresponding to the
resistivity values calculated using the phase measurements and amplitude measurements from
the resistivity logging tools, respectively.
The images 800 and 850 illustrate resistive features in an otherwise
homogenously conductive formation. Image 800, for example, identifies a resistive 1.2 inch
fracture 802 at a depth of 50 feet in the conductive formation. Image 850, in contrast, identifies
a 10 foot resistive layer 804 of the otherwise homogenous formation. Fig. 9 illustrates similar
images 900 and 950 to those in Fig. 8, except that the 1.2 inch fracture 902 in image 900
comprises a conductive 1.2 inch fracture in an otherwise homogenously resistive formation, and
10 foot layer 904 comprises a conductive layer in the resistive formation. The resistive and
conductive portions of the images are identifiable through their corresponding resistivity values.
In images 800, 850, 900, and 950, the darker colors are associated with higher resistivity values
and the lighter colors are associated within lower resistivity values. By identifying abrupt
changes in resistivity values, illustrated by the abrupt dark-to-light and light-to-dark changes in
Figs. 8 and 9, fractures may be identified. For example, a first set of resistivity values that are
higher that the resistivity values in adjacent depths and azimuthal orientations may indicate a
resistive fracture in a conductive formation, illustrated by the dark section within the otherwise
light background in Fig. 8. Conversely, a second set of resistivity values that are lower that the
resistivity values in adjacent depths and azimuthal orientations may indicate a conductive
fracture in a resistive formation, illustrated by the light section within the otherwise dark
background in Fig. 9.
In certain embodiments, filters may be applied to the induction or propagation
resistivity images to cancel the polarization effect on the boundaries of the fracture and to
enhance the resistivity contrast between the fracture and the surrounding formation. One
example filter is a binary filter than utilizes a threshold level and sets at a first value any
resistivity value below the threshold and sets at a second value any resistivity value above the
threshold. Figs. 10 and 11 are charts illustrating phase resistivity values as a solid line and
filtered phase resistivity values as a dashed line for a 0.9 foot fracture at 2 1 feet of depth. As can
be seen, the filtered resistivity values provide a step contrast at the top of the fracture and the
bottom of the fracture with respect to the depth in the formation, with the fracture in Fig. 10
comprising a conductive fracture (high-low-high) and the fracture in Fig. 1 comprising a
resistive fracture (low-high-low). Notably, the step contrast of the filtered resistivity values may
simplify the image processing techniques needed to located and characterize a fracture.
In certain embodiments, the azimuthal angle between the fracture and the tool
also may be determined from the filtered resistivity values and/or induction or propagation
resistivity images, although filtering is not required. For example, the azimuthal angle may be
determined by identifying the bin in which the fracture is first detected. Fig. 12 is a diagram
illustrating the azimuthal response of two bins of a resistivity logging apparatus to a resistive
fracture in a conductive formation, according to aspects of the present disclosure. The two bins
comprise a Rup bin, corresponding to the bin pointed away from the fracture, and an Rdn bin
opposite the Rup bin and pointed toward the fracture. Fig. 12 further plots the average resistivity
value for the tool Ravg. As can be seen, when the tool nears an upper boundary of a resistive
fracture, the Rdn bin will show an increased resistivity value before the Rup bin, due to its
azimuthal position with respect to the fracture. As the tool approaches the lower boundary of the
fracture, the resistivity value of the Rdn bin will drop due to the surrounding conductive
formation, while the resistivity value for the Rup bin will increase. Accordingly, the
measurement directly up, or away from the fracture will represent the minimum resistivity
response from the fracture and the measurement directly down, or towards the fracture will
represent the maximum resistivity value.
Additionally, the azimuthal angle may be determined by identifying resistivity
maximums and minimum with respect to axial locations in the borehole. Fig. 13 is a diagram
illustrating an example azimuthal resistivity response at one depth within a borehole, according
to aspects of the present disclosure. As can be seen, the azimuthal resistivity response is a
waveform with a minimum corresponding to a zero angle and a maximum corresponding to a
180 degree angle, opposite the zero angle. Depending on the type of formation and fracture (i.e.,
conductive versus resistive) the facture may be azimuthally located at either the maximum or
minimum resistivity value in the graph. In certain embodiments, a curve fitting method may be
used to generate the substantially sine-wave shape and to smooth the responses to better identify
the maximum and minimum resistivity values with respect to azimuthal angle. Similar responses
may be generated throughout a fracture bed, and the combined results may be used to accurately
identify the azimuthal angle of the fracture.
In certain embodiments, once the azimuthal angle of the fracture is identified, the
bins may be renumbered so that the upper boundary of the fracture is located at bin 1 and the
lower boundary is opposite bin 1. For example, depending on the type of formation, Rup or Rdn
may be set to correspond to bin 1 and the other one of Rup or Rdn may be set to correspond to
the bin opposite bin 1. As illustrated above, the induction or propagation resistivity images may
be plotted with respect to the azimuthal orientation of the resistivity values by bin number. By
renumbering the bins, the induction or propagation resistivity images for different fractures may
have similarly positioned induction or propagation resistivity images. Example shifted
propagation resistivity images are shown in Fig. 14, where the upper boundaries of the fracture
are positioned in bin 1, and the lower boundaries are positioned in the middle of the plot.
Shifting the bin numbering may simplify the computational requirements to
identify and characterize the fractures. For example, if image or data processing algorithms are
used, standardizing the location of the upper and lower boundaries of the fracture may simplify
the algorithm. Likewise, pattern matching techniques may be used to identify fractures and
determine their characteristics, including their size, shape, average resistivity values, edge
locations, and orientation. If the upper and lower boundaries are similarly positioned within the
induction or propagation resistivity images, the algorithms may be designed to look in
designated places for the upper and lower boundaries, instead of searching within the induction
or propagation resistivity images for the boundaries. Calculating the size of the fracture from the
induction or propagation resistivity images may be similarly simplified.
According to aspects of the present disclosure, one pattern matching technique
may comprise constructing a synthetic fracture image using model fracture characteristics. The
synthetic fracture image may be compared to the identified fracture in the induction or
propagation resistivity image, and the model fracture characteristics may be adjusted until the
synthetic fracture image matches the fracture within a pre-determined threshold. In another
embodiment, the pattern matching technique may comprise determining a set of potential
fracture characteristics combinations, and for each combination of potential fracture
characteristics, generating a model fracture image, correlating at least one characteristic of the
modeled resistivity image with identified fracture, and determining a correlation value. The
fracture characteristic with the higher correlation value may be selected. The fracture model
may be a ID, 2D or 3D simulation of electromagnetic wave propagation in downhole
environment. It may be based on finite-difference, finite-element, method of moment and
integral equation methods. The fracture parameters that produce the best matching are accepted
as the solution.
Fig. 15 is a flow diagram of an example process, according to aspects of the
present disclosure. Step 1501 may comprise positioning a magnetic dipole transmitter and a
magnetic dipole receiver within a borehole in a subterranean formation. At least one of the
magnetic dipole transmitter and the magnetic dipole receiver being tiled with respect to an axis
of the borehole. In certain embodiments, both of the magnetic dipole transmitter and the
magnetic dipole receiver may be tilted with respect to the axis of the borehole. The magnetic
dipole transmitter and the magnetic dipole receiver may be coupled, for example, to a wireline
tool or a LWD element of a drilling assembly.
Step 1502 may comprise generating a time-varying EM signal with the magnetic
dipole transmitter, and step 1503 may comprise measuring a response of the formation to the
time-varying EM signal using the magnetic dipole receiver. The response may include at least
two depths of a formation and at least two azimuthal orientations of the formation with respect to
the axis of the borehole. In certain embodiments, the response may comprise amplitude, phase,
and attenuation values of the formation to the EM signal. In certain embodiments, measuring the
response may comprise receiving a first measurement from the magnetic dipole receiver
corresponding to a first azimuthal orientation with respect to the axis of the borehole and
calculating a second measurement corresponding to a second azimuthal orientation with respect
to the axis of the borehole.
Step 1504 may comprise generating an image of the formation based, at least in
part, on the response. The response may be divided into azimuthal bins, and each depth or layer
of the borehole or formation may have a separate group of azimuthal bins. The image of the
formation may be generated by plotting a visualization of the azimuthally- and depth- oriented
response values. In certain embodiments, generating the first image of the formation based, at
least in part, on the response and the synthetic fracture image comprises generating the first
image of the formation using at least one of phase values from the response, amplitude values
from the response, attenuation values from the response, and resistivity values calculated using at
least one of the phase values, amplitude values, and attenuation values from the response. In
certain embodiments, calculating the separate resistivity values may comprise calculating at least
one of a geosignal and a compensated signal for each of the azimuthal bins and determining the
separate resistivity value for each of the plurality of bins using the calculated geosignal or
compensated signal and at least one of a look-up table and an inversion algorithm.
Step 1505 may comprise determining at least one fracture characteristic based, at
least on part, on the first image and a synthetic fracture image. In certain embodiments,
determining at least one fracture characteristic based, at least on part, on the first image and the
synthetic fracture image may comprise constructing the synthetic fracture image using model
fracture characteristics and comparing the synthetic fracture image to feature in the first image.
The feature in the first image may comprise a portion or section of the first image that is
suspected of containing a fracture. The model fracture characteristics may be adjusted until the
synthetic fracture image matches the feature within a threshold.
In other embodiments, determining at least one fracture characteristic based, at
least on part, on the first image and the synthetic fracture image may comprise determining a set
of potential model fracture characteristics combinations and for each combination of potential
model fracture characteristics, generating a synthetic fracture image, correlating a first feature of
the synthetic image with a second feature in the first image, and determining a correlation value.
As described above, the feature of the first image may comprise a portion of the first image. The
potential model fracture characteristic with the highest correlation value may then be selected as
the fracture characteristic for the first image.
In certain embodiments, correlating the first feature of the synthetic image with
the second feature in the first image may include determining a type of the second feature. In
certain embodiments, a type of the second feature may be determined by determining if the
second feature comprises one of a first set of resistivity values that are higher than the resistivity
values at adjacent depths in the formation, and a second set of resistivity values that are lower
than the resistivity values at adjacent depths in the formation.
An azimuthal shift and a depth shift between the first feature and second feature
may be determined. An azimuthal orientation of the second feature may be identified by
determining a first azimuthal orientation pointing away from the second feature and a second
azimuthal orientation pointing toward the second feature based on the type of the second feature.
One of the first image and the synthetic fracture image so that the first feature and second feature
are aligned in azimuth and depth.
The methods described above may be implemented in a system with a magnetic
dipole transmitter and receiver and an information handling system communicably coupled to
the magnetic dipole receivers. The information handling system may comprise a processor and a
set of instructions that when executed by the processor cause the processor to generate a timevarying
electromagnetic (EM) signal with the magnetic dipole transmitter; measure a response of
the formation to the time-varying EM signal using the magnetic dipole receiver, the response
comprising at least two depths of a formation and at least two azimuthal orientations of the
formation with respect to the axis of the tool body; generate a first image of the formation based,
at least in part, on the response; and determine at least one fracture characteristic based, at least
on part, on the first image and a synthetic fracture image. The fracture characteristic may
comprise at least one of a presence of a fracture and/or the shape, size, average resistivity value,
and/or edge location of the fracture.
Therefore, the present disclosure is well adapted to attain the ends and advantages
mentioned as well as those that are inherent therein. The particular embodiments disclosed
above are illustrative only, as the present disclosure may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having the benefit of the teachings
herein. Furthermore, no limitations are intended to the details of construction or design herein
shown, other than as described in the claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified and all such variations are
considered within the scope and spirit of the present disclosure. Also, the terms in the claims
have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the
patentee. The indefinite articles "a" or "an," as used in the claims, are defined herein to mean
one or more than one of the element that it introduces.

What is claimed is:
. A method for fracture identification and characterization, comprising:
positioning a magnetic dipole transmitter and a magnetic dipole receiver within a
borehole in a subterranean formation, at least one of the magnetic dipole transmitter and the
magnetic dipole receiver being tilted with respect to an axis of the borehole;
generating a time-varying electromagnetic (EM) signal with the magnetic dipole
transmitter;
measuring a response of the formation to the time-varying EM signal using the
magnetic dipole receiver, the response comprising at least two depths of the formation and at
least two azimuthal orientations of the formation with respect to the axis of the borehole;
generating a first image of the formation based, at least in part, on the response;
and
determining at least one fracture characteristic based, at least on part, on the first
image and a synthetic fracture image.
2. The method of claim 1, wherein generating the first image of the formation based,
at least in part, on the response and the synthetic fracture image comprises generating the first
image of the formation using at least one of
phase values from the response;
amplitude values from the response;
attenuation values from the response; and
resistivity values calculated using at least one of the phase values, amplitude
values, and attenuation values from the response.
3. The method of claim 1, wherein determining at least one fracture characteristic
based, at least on part, on the first image and the synthetic fracture image comprises
constructing the synthetic fracture image using model fracture characteristics;
comparing the synthetic fracture image to a feature in the first image; and
adjusting the model fracture characteristics until the synthetic fracture image
matches the feature within a threshold.
4. The method of claim 1, wherein determining at least one fracture characteristic
based, at least on part, on the first image and the synthetic fracture image comprises
determining a set of potential model fracture characteristics combinations;
for each combination of potential model fracture characteristics,
generating a synthetic fracture image from the combination of potential
model fracture characteristics;
correlating a first feature of the synthetic fracture image with a second
feature in the first image; and
determining a correlation value; and
determining the potential model fracture characteristic with the highest correlation
value among all combinations of potential model fracture characteristics.
5. The method of claim 4, wherein correlating the first feature of the synthetic
fracture image with the second feature in the first image comprises
determining a type of the second feature;
identifying an azimuthal shift between the first feature and the second feature;
identifying a depth shift between the first feature and the second feature; and
shifting one of the first image and the synthetic fracture image so that the first
feature and the second feature are aligned in azimuth and depth.
6. The method of claim 5, wherein determining the correlation value comprises
calculating the correlation of image values between the shifted one of the first image and the
synthetic fracture image and other one of the first image and the synthetic fracture image.
7. The method of claim 5, wherein determining the type of the second feature
comprises determining if the feature comprises one of
a first set of resistivity values that are higher than the resistivity values at adjacent
depths in the formation; and
a second set of resistivity values that are lower than the resistivity values at
adjacent depths in the formation.
8. The method of any one of claims 1-4, wherein determining at least one fracture
characteristic based, at least on part, on the first image and the synthetic fracture image
comprises determining at least one of a presence, shape, size, average resistivity value, and edge
location of the fracture.
9. The method of any one of claims 1-4, wherein both the magnetic dipole
transmitter and the magnetic dipole receiver are tilted with respect to the axis of the borehole.
10. The method of any one of claims 1-4, wherein the magnetic dipole transmitter and
the magnetic dipole receiver are co-located with respect to the axis of the borehole.
11. A system for fracture identification and characterization, comprising:
a magnetic dipole transmitter coupled to a tool body;
a magnetic dipole receiver coupled to the tool body, at least one of the magnetic
dipole transmitter and the magnetic dipole receiver being tiled with respect to an axis of the tool
body;
an information handling system communicably coupled to the magnetic dipole
transmitter and the magnetic dipole receiver, the information handling system comprising a
processor and a memory device coupled to the processor, the memory device containing a set of
instruction that, when executed by the processor, cause the processor to:
generate a time-varying electromagnetic (EM) signal with the magnetic
dipole transmitter;
measure a response of the formation to the time-varying EM signal using
the magnetic dipole receiver, the response comprising at least two depths of a formation and at
least two azimuthal orientations of the formation with respect to the axis of the tool body;
generate a first image of the formation based, at least in part, on the
response; and
determine at least one fracture characteristic based, at least on part, on the
first image and a synthetic fracture image.
1 . The system of claim 11, wherein the set of instructions that causes the processor
to generate the first image of the formation based, at least in part, on the response and the
synthetic fracture image further causes the processor to generate the first image of the formation
using at least one of
phase values from the response;
amplitude values from the response;
attenuation values from the response; and
resistivity values calculated using at least one of the phase values, amplitude
values, and attenuation values from the response.
13. The system of claim 11, wherein the set of instructions that causes the processor
to determine at least one fracture characteristic based, at least on part, on the first image and the
synthetic fracture image further causes the processor to
construct the synthetic fracture image using model fracture characteristics;
compare the synthetic fracture image to an feature in the first image; and
adjust the model fracture characteristics until the synthetic fracture image matches
the feature within a threshold.
14. The system of claim 11, wherein the set of instructions that causes the processor
to determine at least one fracture characteristic based, at least on part, on the first image and the
synthetic fracture image further causes the processor to
determine a set of potential model fracture characteristics combinations;
for each combination of potential model fracture characteristics,
generate a synthetic fracture image from the combination of potential
model fracture characteristics;
correlate a first feature of the synthetic fracture image with a second
feature in the first image; and
determine a correlation value; and
determine the potential model fracture characteristic with the highest correlation
value among all combinations of potential model fracture characteristics.
15. The system of claim 14, wherein the set of instructions that causes the processor
to correlate the first feature of the synthetic fracture image with the second feature in the first
image further causes the processor to
determine a type of the second feature;
identify an azimuthal shift between the first feature and the second feature;
identify a depth shift between the first feature and the second feature; and
shift one of the first image and the synthetic fracture image so that the first feature
and the second feature are aligned in azimuth and depth.
16. The system of claim 15, wherein the set of instructions that causes the processor
to determine the correlation value further causes the processor to calculate the correlation of
image values between the shifted one of the first image and the synthetic fracture image and
other one of the first image and the synthetic fracture image.
17. The system of claim 15, wherein the set of instructions that causes the processor
to determine the type of the second feature further causes the processor to determine if the
second feature comprises one of
a first set of resistivity values that are higher than the resistivity values at adjacent
depths in the formation; and
a second set of resistivity values that are lower than the resistivity values at
adjacent depths in the formation.
18. The system of any one of claims 11-14, wherein the fracture characteristic
comprises at least one of a presence, shape, size, average resistivity value, and edge location of
the fracture.
19. The system of any one of claims 11-14, wherein both the magnetic dipole
transmitter and the magnetic dipole receiver are tilted with respect to the axis of the tool body.
20. The system of any one of claims 11-14, wherein the magnetic dipole transmitter
and the magnetic dipole receiver are co-located on the tool body.