CROSS-COUPLING BASED FLUID FRONT MONITORING
BACKGROUND
Oilfield operating companies seek to maximize the profitability of their reservoirs.
Typically, this goal can be stated in terms of maximizing the percentage of extracted
hydrocarbons subject to certain cost constraints. A number of recovery techniques have been
developed for improving hydrocarbon extraction. For example, many companies employ
flooding techniques, injecting a gas or a fluid into a reservoir to displace the hydrocarbons
and sweep them to a producing well. As another example, some heavy hydrocarbons are most
effectively produced using a steam-assisted gravity drainage technique, where steam is
employed to reduce the hydrocarbons' viscosity.
Such recovery techniques create a fluid front between the injected fluid and the fluid
being displaced. The position of the fluid front is a key parameter for the control and
optimization of these recovery techniques, yet it is usually difficult to track due to the
absence of suitably feasible and effective monitoring systems and methods. Where the use of
seismic surveys, monitoring wells and/or wireline logging tools is infeasible, operators may
be forced to rely on computer simulations to estimate the position of the fluid front, with
commensurately large uncertainties. Yet suboptimal operations may cause premature
breakthrough where one part of the fluid front reaches the producing well before the rest of
the front has properly swept the reservoir volume. Such premature breakthrough creates a
low-resistance path for the injected fluid to follow and deprives the rest of the system of the
power it needs to function. Prevention of premature breakthrough is generally considered
preventable with adequate forewarning of a fluid front's approach to the producing well(s).
DESCRIPTION OF THE DRAWINGS
Accordingly, there are disclosed in the drawings and the following description various
cross-coupling compensation methods and systems employing cross-coupling based fluid
front monitoring via non-parallel antennas around a permanently-installed casing string. In
the drawings:
Fig. 1 is a schematic depiction of an illustrative permanent electromagnetic (EM)
fluid front monitoring system.
Fig. 2 is a schematic depiction of a steam-assisted gravity drainage operation.
Fig. 3 shows an illustrative multicomponent EM transducer module.
Figs. 4A-4B show geometrical inversion parameters for an illustrative fluid front
inversion.
Figs. 5A-5B plot a fluid front signal response as a function of different parameters.
Fig. 6 is a schematic depiction of a fluid front propagating from an injector well.
Figs. 7A-7C show illustrative transducer array configurations.
Fig. 8 is a flow diagram of an illustrative fluid front monitoring method.
It should be understood, however, that the specific embodiments given in the drawings and
detailed description thereto do not limit the disclosure. On the contrary, they provide the
foundation for one of ordinary skill to discern the alternative forms, equivalents, and
modifications that are encompassed together with one or more of the given embodiments in
the scope of the appended claims.
DETAILED DESCRIPTION
Certain disclosed device, system, and method embodiments provide fluid front
monitoring via permanent, casing-mounted electromagnetic (EM) transducers. One or more
boreholes is provided with a casing string having one or more transmit antennas that encircle
the casing string and one or more receive antennas that encircle the casing string, with at least
one receive antenna oriented differently from at least one transmit antenna to provide
sensitivity to at least one cross-component signal. Based at least in part on the crosscomponent
signal, a processor unit derives an estimated distance to a fluid front, and may
further determine a direction and orientation of the fluid front for display to a user. Signals
from an array of transmit and receive antennas may be combined, optionally with signals
from other boreholes, to locate and track multiple points on the fluid front. In response to the
determined location and progress of the front, the processor unit may further provide control
settings to adjust injection and/or production rates.
Fig. 1 shows a well 102 equipped with an illustrative embodiment of a permanent
electromagnetic (EM) fluid front monitoring system. The illustrated well 102 has been
constructed and completed in a typical manner, and it includes a casing string 104 positioned
in a borehole 106 that has been formed in the earth by a drill bit. The casing string 104
includes multiple casing tubulars (usually 30 foot long steel tubulars) connected end-to-end
by couplings 108. Alternative casing types include continuous tubing and, in some rare cases,
composite (e.g., fiberglass) tubing. Cement 110 has been injected between an outer surface of
the casing string 104 and an inner surface of the borehole 106 and allowed to set. The cement
enhances the structural integrity of the well and seals the annulus around the casing against
undesired fluid flows. Though well 102 is shown as entirely cemented, in practice certain
intervals may be left without cement, e.g., in horizontal runs of the borehole where it may be
desired to facilitate fluid flows.
Perforations 114 have been formed at one or more positions along 106 to facilitate the
flow of a fluid 116 from a surrounding formation into the borehole and thence to the surface.
The casing string may include pre-formed openings 118 in the vicinity of the perforations
114, or it may be perforated at the same time as the formation. Typically the well 102 is
equipped with a production tubing string positioned in an inner bore of the casing string 104.
(A counterpart production tubing string 112 is visible in the cut-away view of well 152.) One
or more openings in the production tubing string accept the borehole fluids and convey them
to the earth's surface and onward to storage and/or processing facilities via production outlet
120. The wellhead may include other ports such as port 122 for accessing the annular
space(s) and a blowout preventer 123 for blocking flows under emergency conditions.
Various other ports and feed-throughs are generally included to enable the use of external
sensors 124 and internal sensors. Illustrative cable 126 couples such sensors to a well
interface system 128. Note that this well configuration is merely for illustrative purposes, is
not to scale, and is not limiting on the scope of the disclosure.
The interface system 128 typically supplies power to the transducers and provides
data acquisition and storage, possibly with some amount of data processing. The permanent
EM monitoring system is coupled to the interface system 128 via an armored cable 130,
which is attached to the exterior of casing string 104 by straps 132 and protectors 134.
(Protectors 134 guide the cable 130 over the couplings 108 and shield the cable from being
pinched between the coupling and the borehole wall.) The cable 130 connects to one or more
electromagnetic transducer modules 136, 137 attached to the casing string 104. Each of the
transducer modules 136, 137 may include a layer of nonconductive material having a high
permeability to reduce interference from casing effects.
Fig. 1 further shows a second well, injection well 152, having a second casing string
154 in a borehole 155, with one or more EM transducer modules 156, 157 attached to the
casing string and communicating via one or more cables 158 to a second well interface
system 160. The second well interface system may be connected in a wired or wireless
fashion to the first well interface system or to a central data processing system that
coordinates the operation of the wells. As the injection well drives a fluid such as water, C0 2,
or natural gas, into the formation, the injected fluid displaces the desired hydrocarbons and
sweeps them outward from the injection well. The presence of any producing wells in the
vicinity reduces the formation pressure, causing the displaced fluid (and the injected fluid) to
preferentially migrate toward the producing wells. The interface between the displaced fluid
and the injected fluid is called the "front". Oil companies are interested in monitoring the
movement of the front and to know in advance when it is about to reach the production well.
Though Fig. 1 shows vertical wells, these principles also apply to horizontal and
deviated wells. They may also apply where the injected fluid does not act as a drive fluid. For
example, Fig. 2 shows a steam-assisted gravity drainage (SAGD) operation, in which an
injection well 202 circulates and injects steam into a surrounding formation. As the thermal
energy from the steam reduces the viscosity of the heavy oil in the formation, the heavy oil
(and steam condensate) 204 is drawn downward by gravity to a producing well 206 drilled
parallel and from about 5-20 ft lower. In this manner, the steam forms an expanding "steam
chamber" 208 that delivers thermal energy to more and more heavy oil. The chamber
primarily grows in an upward direction, but there is a front 210 that gradually moves
downward towards the producing well 206. Excessive injection rates will drive the front 210
prematurely to the producing well, creating an unwanted flow path that severely reduces the
operation's efficiency. Either or both of the wells 202, 206, may be equipped with EM
transducer modules to track the distance 212 of front 210. (The front is detectable because
injected steam has different resistive and dielectric properties than the formation and the
heavy oil.)
Often companies will drill additional wells in the field for the sole purpose of
monitoring the front and predicting its arrival at the producing wells. In the systems of Figs. 1
and 2, additional wells and well interfaces may be included in the coordinated operation of
the field and the permanent EM monitoring system. (Some system embodiments employ EM
transducer modules in only one well, but it is generally preferred to provide additional EM
transducer modules on the surface and/or in other nearby wells.) The additional wells may be
single-purpose wells (i.e., only for injection, production, or monitoring), or they may serve
multiple purposes, some of which may change over time (e.g., changing from a producing
well to an injection well).
Returning to Fig. 1, the illustrated system further includes surface transducer modules
170. The surface transducer modules 170 may employ spaced-apart electrodes that create or
detect EM signals, wire coils that create or detect EM signals, or magnetometers or other EM
sensors to detect EM signals. At least one of the transducer modules 136, 156, 170 transmits
EM signals while the receiver modules 137, 157 obtain responsive measurements. In some
implementations, each of the transducer modules is a single-purpose module, i.e., suitable
only for transmitting (136, 156) or receiving (137, 157), but it is contemplated that in at least
some implementations, the system includes one or more transducer modules that can perform
both transmitting and receiving.
The EM transducer modules 136, 156 can transmit or receive arbitrary waveforms,
including transient (e.g., pulse) waveforms, periodic waveforms, and harmonic waveforms.
The transducer modules 137, 157 can further measure natural EM fields including
magnetotelluric and spontaneous potential fields. Without limitation, suitable EM signal
frequencies for reservoir monitoring include the range from 1 Hz to 10 kHz. In this frequency
range, the modules may be expected to detect signals at transducer spacings of up to about
200 feet, though of course this varies with transmitted signal strength and formation
conductivity. Lower (below 1 Hz) signal frequencies may be suitable where magnetotelluric
or spontaneous potential field monitoring is employed. Higher signal frequencies may also be
suitable for some applications, including frequencies as high as 500 kHz, 2 MHz, or more.
Fig. 1 further shows a processor unit 180 that communicates wirelessly with the well
interface system 128 to obtain and process EM measurement data and to provide a
representative display of the information to a user. The processor unit 180 can take different
forms including a tablet computer, laptop computer, desktop computer, and virtual cloud
computer. Whichever processor unit embodiment is employed includes software that
configures the unit's processor(s) to carry out the necessary processing and to enable the user
to view and preferably interact with a display of the resulting information. The processing
includes at least compiling a time series of measurements to enable monitoring of the time
evolution, but may further include the use of a geometrical model of the reservoir that takes
into account the relative positions and configurations of the transducer modules and inverts
the measurements to obtain one or more parameters such as fluid front distance 181 (or 182),
direction, and orientation. Additional parameters may include a resistivity distribution and an
estimated water saturation.
The processor unit 180 may further enable the user to adjust the configuration of the
transducers, varying such parameters as firing rate of the transmitters, firing sequence of the
transmitters, transmit amplitudes, transmit waveforms, transmit frequencies, receive filters,
and demodulation techniques. In some contemplated system embodiments, the processor unit
further enables the user to adjust injection and/or production rates to optimize production
from the reservoir.
Fig. 3 is a partial cross-section of an illustrative EM transducer module 302 coupled
to armored cable 130 by couplers 304. The module body 306 is designed to fit over a casing
tubular as the casing tubular is being used to extend the casing string. Alternatively, special
casing tubulars may be manufactured with the EM transducer module formed in place on the
exterior of the casing or, in some embodiments, partially embedded in the wall of the casing
tubular. Module body 306 may be fixed in place with, e.g., clamps or adhesive. The
illustrated module 302 includes three tilted antennas 308, 310, 312, each tilted by the same
amount, but skewed in different azimuthal directions. The azimuthal directions are preferably
spaced 120° apart. The amount of tilt can vary, so long as the angle between the antenna axis
and the tool axis is greater than zero. Contemplated tilts include 30°, 45° and 54.7°. (The
latter tilt makes the three antennas orthogonal to each other.) Some alternative module
embodiments employ one untilted (i.e., coaxial) antenna. Many variations are possible,
though it is contemplated that at least one receive antenna will be responsive to at least one
transmit antenna with a different (i.e., non-parallel) orientation. In the embodiments of Fig. 1,
triaxial receive antennas 137, 157, respond to triaxial transmit antennas 136, 156.
A protective shell 314 covers the antennas, which may be seated in grooves for even
greater protection. Some contemplated embodiments include fins or centralizer ribs to further
protect the module. The body of module 306 preferably includes at least a layer of a
nonconductive material having a high magnetic permeability, and in some embodiments, the
entire body of the module comprises such a material. With such a layer between the antennas
and the casing, the dissipative effects of the casing can be reduced. The shell and any fins or
ribs are preferably made with a material having a low magnetic permeability.
An embedded electronics module 316 may coordinate the operation of the antennas
and provide communication with the well interface 128. In at least some embodiments, the
modules are coordinated to operate in a fashion similar to Halliburton's Azimuthal Deep
Resistivity tool, with one or more coaxial transmit antennas and one or more tilted receive
antennas. Though the ADR tool employs spaced-apart transmit and receive antennas, some
contemplated embodiments of the fluid front monitoring system employ co-located transmit
and receive antennas. With multi-axial transmit and/or receive antennas, it is possible to
resolve the ZZ coupling from the ZX and ZY couplings and to "scan" in multiple azimuthal
directions from the casing string. With a sinusoidal signal frequency of 20 kHz and a
transmit-to -receiver spacing of 560 inches, the system may be expected to detect an
approaching front from nearly 100 ft away. Multiple receivers for phase difference and/or
amplitude ratio measurements will enable rejection of unwanted effects such as calibration
errors and drifts in the electrical circuitry.
Where a multi-axial receiver is not feasible, the contemplated embodiments have the
receive antenna tilted "toward" the transmitter and the expected arrival direction of the front.
In other words, the axis of the tilted antenna is in a plane that includes a vector from the
receive antenna to the transmit antenna and a vector from the receive antenna to the nearest
point on the arriving front, with one side of the axis positioned between the vectors so as to
form an acute angle with each vector. The receive signal will be a blend of ZZ and ZX
couplings.
Figs. 4A-4B define certain geometrical parameters that are useful for the ensuing
discussion. Fig. 4A shows a side view of casing 402 extending along a downwardly-directed
casing axis (the Z-axis). A front 404 is shown at a distance D from the receiver location. The
front 404 need not be parallel to the casing axis, and in fact Fig. 4A shows the front at a
relative dip angle Q (measured from the positive Z axis). Fig. 4B shows an end view of the
casing 402, with an X-axis defining a zero-azimuth, which may be the high-side of the
borehole or, for a vertical well, may be North. The azimuth angle f , or "strike", of the front
404 is measured counterclockwise from the X-axis. Similarly, the tilt of the antennas can also
be specified in terms a tilt angle (relative dip) Qand azimuth f of the antenna axis.
With these parameters in mind, Figs. 5A-5B show synthetic data for a fluid front
monitoring system. The synthetic model assumes a fluid front parallel to the casing axis (i.e.,
relative dip 90°) at an azimuth of zero. Resistivity of the formation with the undisplaced fluid
is taken as 20 ohm-m, and the resistivity of the formation with the injected fluid is taken as
1 ohm-m. A coaxial transmit antenna is separated from the receive antenna by 100 inches.
Fig. 5A shows the resulting signal strength as a function of fluid front distance for different
receive antenna orientations. (Negative distance means the fluid front has passed the casing.)
With a coaxial receive antenna that measures the ZZ coupling component, the signal strength
from the approaching fluid front increases until the front approaches within about 100 inches
of the casing, drops until the front comes within about 25 inches, rises until the front reaches
the casing, but then drops again as the front passes the casing before finally increasing to a
steady maximum value. The distance dependence of this signal is undesirably complex,
though at distances beyond 100 inches it is monotonic and the strongest of the signals shown
here.
With a receive antenna tilted at 90° in the direction of the approaching front to
measure the ZX coupling component, the signal strength dependence is much simpler, with a
peak where the front reaches the casing and a steady fall-off thereafter. Similar performance
is observed for a 90° tilted antenna oriented at 45° to the approaching front. Fig. 5A also
shows a curve for an antenna tilted at 45° in the direction of the approaching front. This curve
is a blend of the ZZ and ZX responses, having a comparable signal strength at large distances
and a nearly-monotonic distance dependence at short distances.
Fig. 5B shows signal strength as a function of antenna azimuth for untilted (ZZ
coupling) and 90° tilted receive antennas (cross-coupling) at four different distances from the
front: 5, 10, 25, and 50 ft. The untilted antennas, of course, show no azimuthal dependence,
while the tilted antennas show nulls at 90° and 270° of azimuth. At short distances, the crosscoupling
signals are comparable and in some orientations, stronger than the direct coupling
signals. When the monotonic distance dependence is taken into account, the cross-coupling
signals become very desirable for tracking an approaching front. Moreover, the crosscoupling
signals enable tracking of the front even after it has passed the casing, making it
possible to track the fluid front even from behind. It can also be seen that for a fluid front that
is close to the sensor, the percentage of the XZ signal relative to the ZZ signal is much higher
than the cases where the fluid front is farther out. However, even in the case of a fluid front at
50 feet, XZ constitutes about 1% of the ZZ signal, which should be sufficient to enable
azimuthal interpretation.
Thus, by using electromagnetic tilted receive antennas, a large lateral sensitivity is
achieved. Modeling and experience have shown that the use of a ZX antenna configuration
along with geosignal processing (i.e., normalizing the receive signal with an azimuthallyaveraged
signal) conveys much higher sensitivity to events approaching the tubular, than a
ZZ configuration. The latter, in turn, is known to be even more sensitive than an electrode
galvanic type device.
The inductive system described above is not only sensitive to approaching fluid
fronts, but also other static inhomogeneous formation features. That is, the receive signals
will have a contribution from the background and a contribution from the fluid front. A
calibration operation can be applied to remove the background contribution and enable
subsequent processing to focus on the fluid front contribution. In at least some embodiments,
this operation consists of making a background measurement when the fluid front is far away
and subtracting it from any subsequent measurement. This subtraction ensures that only
changes due to fluid front are measured. It also ensures that fluid front can be detected as far
away as possible.
When measurements by multiple subarrays are combined, a more complete view of
the approaching front can be obtained. Time-domain and/or frequency domain
electromagnetic signals can be employed to perform accurate real-time inversion, or with
sufficient data from multiple transducers and arrays, to perform accurate imaging and
tomography of the steam injection region. The measurements can be repeated to obtain timelapse
monitoring of the injection process. In addition, the conductive casing used for nearby
wells will make those wells detectable via the electromagnetic signals.
Fig. 6 shows an overhead perspective of a field having an injection fluid front 602
propagating outwards from an injection well 604 towards a producing well 606. Monitoring
wells 608, 610, may be provided to enable better monitoring of the front in the region
intermediate the injection and producing wells. The positions of the wells and the EM
transducers, together with the operating parameters such as transmit signal frequencies, can
be chosen using optimization via numerical simulations and/or measurements from LWD and
wireline tools during the drilling process. The design parameters are chosen to obtain
adequate range and resolution with a minimum cost.
Figs. 7A-7C show a casing 702 with various illustrative array configuration modes for
tracking an approaching fluid front 704. Fig. 7A shows a "common-offset" configuration
mode having multiple sets of equally-spaced transmit and receive antennas. (If collocated
transmitters and receivers are employed, the common offset would be zero.) Fig. 7B shows a
"common-source" configuration mode having multiple receiver antennas responding to a
single transmit antenna. Fig. 7C shows a "common-midpoint" configuration mode having
multiple sets of transmit-receive antennas with a shared midpoint. Common-source and
common-midpoint modes can be categorized as multi-offset modes. In general, multi-offset
modes offer imaging advantages over common-offset mode, including improved signal to
noise ratio, increased depth penetration, enhanced reflector continuity and lateral imaging. In
practice, the chosen array configuration is not likely to be restricted to single-purpose
transducers (i.e., transmit or receive) operating in a single mode, but rather is likely to
employ transceivers and be usable in multiple such modes or a mode that shares features of
common offset, common source, and common midpoint modes.
Fig. 8 is a flow diagram of an illustrative fluid front monitoring method that may be
carried out by processor unit in communication with one or more well interfaces. In block
802, the processor unit obtains the array configuration information including relative
positions of the well casings, the positions of the various electromagnetic transducers, and the
orientations of the transmit and receive antennas and any other sensors. The configuration
information may further include the transmit signal frequencies and/or pulse shapes. Some
embodiments may employ transient or ultra-wideband signals. In block 804, the processor
unit optionally triggers the transmitters, but in any event obtains responsive measurements
from the receivers. In addition to some identification of the measurement time and the
associated transmit and receive antennas, the signal measurements may include signal
strength (e.g., voltage), attenuation, phase, travel time, and/or receive signal waveform. In
block 806, the processor unit performs initial processing to improve the signal-to-noise ratio
of the measurements, e.g., by dropping noisy or obviously erroneous measurements,
combining measurements to compensate for calibration errors, demodulating or otherwise
filtering signal waveforms to screen out-of-band noise, and/or averaging together multiple
measurements.
In addition, the processor may apply a calibration operation to the measurements. One
particular example of a calibration operation determines the ratio of complex voltage or
current signals obtained at two different receivers, or equivalently, determines the signal
phase differences or amplitude ratios. Another illustrative calibration operation subtracts out
the inhomogeneous static formation effect by first making an initial measurement with fluid
front far away, and then subtracting this background measurement from the subsequent
measurements.
In block 808, the processor unit performs an inversion to match the measurements
with a synthetic measurements from a parameterized model. The model parameters may
include formation resistivity R (on both sides of the front), distance (d) from the receiver to
the front, dip angle (Q) between the casing axis and the normal to the front, and azimuth (F)
of the normal relative to a pre-defined X-axis for the receiver. Where an insufficient number
of independent measurements exist, some of these parameters (e.g., formation resistivities)
may be assumed. Where additional independent measurements are available (e.g.
measurements at additional receivers, frequencies, and/or from different wells), the number
of model parameters may be increased to include, e.g., relative positions and orientations of
different wells, distances and orientations of different points on the fluid front, and the shape
of the fluid front. The fluid front shape may be parameterized in different ways. Illustrative
parameterized shapes are an oval with minor and major axes, or an ellipsoid with three axial
diameters.
Blocks 804-808 are repeated, with the derived parameter values from each step being
delivered to an interactive visualization process represented by blocks 812-816. In block 812,
the processor unit provides to a user a display having a representation of the derived
parameter values. The display may include a graphical representation of the fluid front's
position relative to one or more producing wells. Alternative representations include numeric
parameter values, a two-dimensional log of each parameter value as a function of time, or
simplified representations of a comparison between actual position and actual position. One
example of this last representation is a green light when the measured parameter values have
a good match to the desired parameter values and a red light when they do not.
In block 814, the processor unit combines the current parameter values with past
parameter values to derive a fluid front velocity and a time-lapse representation of the fluid
front position. These parameter values may be similarly displayed to the user.
In block 816, the processor unit may automatically adjust a control signal or, in an
alternative embodiment, display a control setting recommendation to a user. For example, if
the front velocity is undesirably high, or if the front has approached closer than desired to the
producing well, the processor unit may perform or recommend a reduction in the production
rate and/or a reduction in the injection rate. Where multiple injection or production zones are
available, the system may redistribute the available production and injection capacity with
appropriate valve adjustments to keep the front's approach as uniform as possible. Blocks
812-816 are repeated as new measurements become available to monitor the fluid front's
position.
In some contemplated system and method embodiments, at least some of the transmit
and/or receive antennas are tilted in different azimuths to enable azimuthal measurements
such as those obtained with a rotating tool as disclosed in US7,659,722 "Method for
azimuthal resistivity measurement and bed boundary detection" to Michael Bittar. To obtain
such measurements from a stationary antenna arrangement, a virtual steering technique can
be employed such as that disclosed in US6,181,138 "Directional Resistivity Measurements
for Azimuthal Proximity Detection of Bed Boundaries" to T. Hagiwara and H. Song.
Numerous variations and modifications will become apparent to those skilled in the
art once the above disclosure is fully appreciated. For example, the foregoing disclosure
focuses on the use of tilted and untilted magnetic dipole antennas, but the disclosed principles
are applicable to other transducer types including multicomponent electric dipoles and further
including various magnetic field sensors such as fiberoptic sensors, MEMS sensors, and
atomic magnetometers. As another example, the casing string need not be straight and the
array of transducers need not be linear. Rather, the transducers can be deployed along a curve
without impairing the operability of the system. It is intended that, where applicable, the
claims be interpreted to embrace all such variations and modifications.

CLAIMS
WHAT IS CLAIMED IS:
1.A monitoring method that comprises:
transmitting a transmit signal with a transmit antenna that encircles a casing string cemented
into a borehole;
receiving one or more responsive receive signals with respective receive antennas that each
encircle the casing string, wherein at least one of said receive antennas is not parallel to the
transmit antenna; and
deriving an estimated distance to a fluid front based at least in part on said receive signals.
2. The method of claim 1, wherein the fluid front is an interface between a formation fluid
and an injected fluid.
3. The method of claim 2, wherein the formation fluid comprises a hydrocarbon and the
injected fluid comprises water or steam.
4. The method of claim 1, wherein said deriving is based at least in part on a crosscomponent
signal strength.
5. The method of claim 1, wherein said deriving is performed without dependence on a
diagonal-component signal strength.
6. The method of claim 1, wherein said deriving is performed based on multiple orthogonal
receive signal components.
7. The method of claim 6, further comprising determining an estimated azimuthal direction to
the fluid front based at least in part on said multiple orthogonal receive signal components.
8. The method of claim 1, further comprising:
performing said transmitting and receiving operations in a second borehole having a second
casing string encircled by a second set of one or more transmit antennas and one or more
receive antennas yielding a second set of receive signals; and
deriving a second estimated distance to the fluid front based at least in part on said second
set of receive signals.
9. The method of claim 8, further comprising estimating a position and shape of the fluid
front based at least in part on the estimated distances.
10. The method of claim 1, wherein the transmit signal is a transient pulse or an ultra
wideband signal.
11. The method of claim 1, wherein the transmit signal comprises multiple carrier
frequencies.
12. The method of claim 1, further comprising repeating said transmitting, receiving, and
deriving to track the estimated distance as a function of time.
13. The method of claim 2, further comprising adjusting an injection or production control
setting based at least in part on the estimated distance.
14. The method of claim 1, further comprising injecting via said casing string a flood fluid
into a formation penetrated by said borehole.
15. The method of claim 1, further comprising producing via said casing string a formation
fluid from a formation penetrated by said borehole.
16. The method of claim 1, wherein said deriving includes subtracting a background
measurement from said receive signals to determine a signal contribution from the front.
17. A monitoring system that comprises:
a borehole that penetrates a subsurface formation;
a casing string cemented in place within the borehole;
at least one transmit antenna that encircles the casing string, said transmit antenna
transmitting a transmit signal into the subsurface formation;
one or more receive antennas that each encircle the casing string, said one or more receive
antennas receiving respective receive signals in response to said transmitting of the transmit
signal, wherein at least one of said one or more receive antennas is not parallel to said
transmit antenna; and
a processing unit that is programmed to derive, based at least in part on said receive signals,
an estimated distance to a fluid front.
18. The system of claim 17, wherein the fluid front is an interface between a formation fluid
and an injected fluid, and wherein the formation fluid comprises a hydrocarbon and the
injected fluid comprises water or steam.
19. The system of claim 17, wherein the system comprises multiple non-parallel transmit
antennas or multiple non-parallel receive antennas, and wherein the processing unit derives
the estimated distance from signal strengths of multiple orthogonal receive signal
components.
20. The system of claim 19, wherein the processing unit further derives an estimated
azimuthal direction to the fluid front based at least in part on said multiple orthogonal receive
signal components.
21. The system of claim 17, wherein said one or more receive antennas comprise an axiallyspaced
array of receive antenna assemblies.
22. The system of claim 21, wherein each assembly comprises receive antennas for multicomponent
signal detection.
23. The system of claim 17, further comprising a second borehole having a second casing
string encircled by a second set of one or more transmit antennas and one or more receive
antennas yielding a second set of receive signals, wherein said processing unit derives a
second estimated distance to the fluid front based at least in part on said second set of receive
signals.
24. The system of claim 23, wherein the processing unit estimates a position and shape of the
fluid front based at least in part on the estimated distances.
25. The system of claim 17, wherein as part of said deriving, the processing unit applies a
calibration operation to the receive signals to remove a background contribution.