DOWNHOLE RANGING FROM MULTIPLE WELLBORES
TECHNICAL FIELD
[0001] The present disclosure relates to software, computer systems, and computerimplemented
media used in forming wellbores in subsurface formations containing
hydrocarbons.
BACKGROUND
[0002] Wellbores formed in subterranean hydrocarbon reservoirs enable recovery of a portion
of the hydrocarbons using production techniques. The hydrocarbons can adhere to the
reservoirs, for example, due to a combination of capillary forces, adhesive forces, cohesive
forces, and hydraulic forces. Steam-assisted gravity drainage (SAGD) is an example of an
enhanced hydrocarbon recovery technique in which heated treatment fluids (for example,
steam) can be applied to the formation to facilitate and enhance recovery of the hydrocarbons
that are adhered to the formation. In an implementation of the SAGD technique, an injection
wellbore can be formed adjacent to a production wellbore, and the heated treatment fluids can
be injected through the injection wellbore into the formation surrounding the production
wellbore. The heated fluids can decrease an adherence of the hydrocarbons to the formation,
thereby releasing the hydrocarbons into the production wellbore.
[0003] While forming (for example, drilling) the injection wellbore, knowledge of a location
of the production wellbore relative to the injection wellbore can be important. Ranging is an
example of a method to control a position of a wellbore being drilled relative to an existing
wellbore. In ranging, an electromagnetic source located in the existing wellbore provides
electromagnetic signals received by sensors in the wellbore being drilled. In another example
of ranging, both the electromagnetic source and the sensors can be located in the wellbore
being drilled. Several conditions, for example, wellbore drilling conditions, can adversely
affect an ability of the electromagnetic source or the sensors (or both) to exchange the
electromagnetic signals, and, consequently, affect ranging in the wellbores.
DESCRIPTION OF DRAWINGS
[0004] FIGS. 1A-1D are schematic, elevation views illustrating examples of multiple
wellbores for ranging.
[0005] FIG. 2 is a block diagram of an example of a system for ranging in multiple wellbores.
[0006] FIG. 3 is an example operational chart that shows relationships between processing,
compensation, and inversion units.
[0007] FIGS. 4A and 4B are plots comparing compensated and uncompensated
electromagnetic signals.
[0008] FIG. 5 is a flowchart of an example process for ranging from multiple wellbores
implementing full compensation.
[0009] FIG. 6 is a flowchart of an example process for ranging from multiple wellbores
implementing partial compensation.
[0010] Like reference symbols in the various drawings indicate like elements.
DETAILED DESCRIPTION
[001 1] This disclosure relates to computer- implemented methods, computer systems, and
computer-readable media for downhole ranging from multiple wellbores using compensated
electromagnetic measurements. In the example of an SAGD application, precise ranging of
the steam injection wellbore can be important. If the injection wellbore intersects the
production wellbore, a blowout can result from the pressure difference between the wells. If
the steam injection wellbore is too far from the production wellbore, the steam injection may
not result in significant increased recovery. The ranging process described here can be used
to determine the distance and precise location while drilling the injection wellbore.
[0012] Ranging focuses on changes in the positions of electromagnetic transmitters and
receivers to provide precise measurements. The transmitters and receivers are disposed in
wellbores for ranging. For example, the transmitters can be placed in a production wellbore
and receivers in a wellbore that is being drilled (for example, for steam injection). The
strength of the transmitters and receivers may not precisely be known. There can be a degree
of variability associated with differences in manufacturing, differences in electronics,
temperature changes, or combinations of them. In addition, an electromagnetic signal may
experience changes, for example, in an approaching target well. Compensation is a technique
that can be used to eliminate or minimize such effects that can adversely affect measurement
of the electromagnetic signals. For example, compensation can eliminate or minimize the
effects of elements (for example, manufacturing differences, electronic differences,
temperature changes, and the like) to ensure that the remaining changes observed and
measured are relevant to the ranging application.
[0013] As described below, one or both of two types of compensation - namely, partial
compensation and full compensation - can be applied to ranging from multiple wellbores
used, for example, in enhanced hydrocarbon recovery. In full compensation
implementations, for example, multiple electromagnetic signal transmitters and multiple
electromagnetic receivers can be located in a production wellbore and an injection wellbore,
respectively. In partial compensation implementations, for example, one electromagnetic
signal transmitter and two electromagnetic sensors or two electromagnetic signal transmitters
and one electromagnetic sensor can be located in a production wellbore and an injection
wellbore, respectively. The production wellbore can be an existing wellbore; the injection
wellbore can be one that is being drilled adjacent the production wellbore for steam injection.
A computer system described below can implement either or both compensation techniques
when interpreting changes in electromagnetic signals between the one or more transmitters
and the one or more receivers to eliminate or minimize some or all of the adverse effects
described above. For example, by implementing the partial or full compensation technique,
the computer system can eliminate or minimize confounding effects of any type of amplitude
or phase shift that can be attributable to electronic drift, drift as a result of temperature
change, or unknown phase or amplitude. After the computer system implements the partial
or full compensation technique (or both), the computer system can use changes observed in
the electromagnetic signal as the basis for measurements for use in ranging the injection
wellbore.
[0014] Implementing partial or full compensation techniques (or both) on the electromagnetic
signals prior to ranging can decrease a reliance on other correction or calibration techniques
that are either complicated or impose strict requirements on electronics. Relative to the other
correction/calibration techniques, the compensation technique can ease requirements on
electronics and result in simpler and more robust measurements. The compensation
techniques described below can provide extended coverage in the area of ranging. The
measurements can be more accurate and robust than conventional compensation techniques.
The compensation techniques can also provide more design flexibility in electronics or
mechanics (or both) implemented in enhanced hydrocarbon recovery techniques, such as
SAGD. The compensation can correct for the effect of temperature, fatigue or corrosion on
sensor electronics such as amplitude or phase drifts. The compensation can also allow easier
deployment of sensors since no in-situ calibration is required.
[0015] FIGS. 1A and IB are schematic, elevation views illustrating examples of multiple
wellbores for ranging implementing full compensation. In some implementations, multiple
transmitters (for example, a first transmitter 102, a second transmitter 104) can be disposed in
multiple wellbores (for example, a first wellbore 110, a second wellbore 122). Each
transmitter (i.e., the first transmitter 102, the second transmitter 104) can transmit
electromagnetic signals. Multiple receivers (for example, a first receiver 114, a second
receiver 116) can be disposed in the multiple wellbores. Each receiver (i.e., the first receiver
114, the second wellbore 116) can receive electromagnetic signals transmitted by the multiple
transmitters. For example, the first transmitter 102 and the second transmitter 104 can be
disposed in a pre-existing production wellbore 110, and can be spaced apart by a distance
ranging between 2 feet and 50 feet. The first receiver 114 and the second receiver 116 can be
disposed in an SAGD wellbore 122 being drilled, and can be spaced apart by a distance
ranging between 2 feet and 50 feet. In sum, at least two transmitters and at least two
receivers can be disposed in at least two wellbores to implement full compensation.
[0016] In some implementations, the first receiver 114 and the second receiver 116 can be
affixed to a Measuring While Drilling (MWD) tool 126 disposed in the SAGD wellbore 122.
Alternatively, or in addition, the sensors can be affixed to a production logging tool, outside
the casings on special housings, inside the casing to transmit or receive from the formation, in
open-hole sections in the wells, or in combinations of them. The sensors can alternatively or
in addition be placed on a production tool inside the casing. A casing can be all or portions of
one or more casing strings disposed in the wellbore.
[0017] FIGS. 1C and ID are schematic, elevation views illustrating examples of multiple
wellbores for ranging implementing partial compensation. In some implementations, a first
transmitter 152 can be disposed in a first wellbore 154 (for example, a pre-existing
production wellbore) to transmit electromagnetic signals. A first receiver 156 can be
disposed in a second wellbore 180 (for example, an SAGD wellbore) to receive the
electromagnetic signals transmitted by the first transmitter. Either a second transmitter or a
second receiver can be disposed in either the first wellbore or the second wellbore to
exchange electromagnetic signals with the first transmitter and the first receiver. For
example, as shown in FIG. 1C, the first receiver 156 and a second receiver 158 can be
disposed on an MWD tool 162 in the second wellbore 160. In another example, as shown in
FIG. ID, a first transmitter 172 and a second transmitter 174 can be disposed in a pre-existing
production wellbore 176 to exchange electromagnetic signals with a receiver 178 disposed on
a production logging tool 182 disposed in an SAGD wellbore 180. In sum, at least a first
transmitter, at least a first receiver, and either a second transmitter or a second receiver can be
disposed in at least two wellbores to implement partial compensation.
[0018] The configuration of the first wellbore relative to the second wellbore (for example,
the arrangement of the wellbore 110 relative to the wellbore 122, the arrangement of the
wellbore 112 relative to the wellbore 124, the arrangement of the wellbore 154 relative to the
wellbore 160, or the arrangement of the wellbore 176 relative to the wellbore 180), and the
arrangement of transmitters and receivers in the first wellbore and the second wellbore are
exemplary. Several other configurations are possible. For example, in both partial and full
compensation implementations, more than two transmitters and more than two receivers can
be disposed in the second wellbore 122 and the first wellbore 110, respectively. In this case,
compensation may be performed in fours. A transmitter and a receiver can be disposed in the
same wellbore in both partial and full compensation implementations. The first wellbore is
substantially perpendicular to the second wellbore , for example, in the formation 140 (FIG.
IA) or in the formation 166 (FIG. 1C). Alternatively, as shown in the formation 150 (FIG.
IB) or in the formation 184 (FIG. ID), a third wellbore can be substantially parallel to a
fourth wellbore.
[0019] One of the two wellbores can be a production wellbore in which one or more
transmitters are disposed. The other wellbore can be an injection wellbore in which a tool
(for example, an MWD tool 128) is disposed. In a full compensation implementation,
multiple receivers (for example, a third receiver 118 and a fourth receiver 120) can be
disposed in the fourth wellbore 124, for example, affixed to the MWD tool 128. In a partial
compensation implementation, one transmitter 178 can be affixed to a tool (for example, the
production logging tool 182) in the wellbore 180. In some implementations, the wellbores
formed in the formation can be at any angle to each other instead of being either substantially
parallel or substantially perpendicular. Transmitters and receivers can be interchangeably
disposed in any wellbore. In sum, the techniques described here can be implemented in
ranging wellbores of any configuration by disposing the sensors (i.e., the transmitters and the
receivers) in any of the two wellbores.
[0020] In some full compensation implementations, the first transmitter 102, the first receiver
114 and the second receiver 116 can be disposed in the first wellbore 110 and the second
wellbore 122 (FIG. 1A) such that an angle formed by a first line connecting the first receiver
114 and the first transmitter 102 and a second line connecting the second receiver 116 and the
first transmitter 106 satisfies a threshold angle, which, in some implementations, can be at
least 5 degrees. Similarly, the third transmitter 106, the third receiver 118 and the fourth
receiver 120 can be disposed in the third wellbore 112 and the fourth wellbore 124 such that
an angle formed by a line connecting the third receiver 118 and the third transmitter 106, and
a line connecting the fourth receiver 120 and the third transmitter 106 satisfies the threshold
angle. In some implementations, the positions of the transmitters and the receivers in the
multiple wellbores can be periodically changed, for example, as one of the wellbores is being
formed relative to the other existing wellbore, such that the angle described above is
maintained to satisfy the threshold angle. The sensitive volume of the sensing system can
include a trapezoidal shape that is formed by connecting the two transmitters and the two
receivers in each case. To increase the coverage, more than two transmitters and more than
two receivers may be used.
[0021] FIG. 2 is a block diagram of an example of a control system 200 for ranging in
multiple wellbores that can implement either partial compensation or full compensation or
both. The control system 200 can be implemented as a computer system (for example, a
desktop computer, a laptop computer, a tablet computer, a personal digital assistant, a
smartphone, and the like) that executes computer instructions stored on a computer-readable
medium 222 to perform the operations described here. The control system 200 can be
connected to a transmitter unit 202 and a receiver unit 204. Each of the transmitter unit 202
and the receiver unit 204 can be implemented as computer instructions stored on the
computer-readable medium 222 and executable in response to instructions from the control
system 200. The transmitter unit 202 can be connected to the multiple transmitters disposed
in the wellbores (for example, the transmitter 106, the transmitter 108). The receiver unit 204
can be connected to the multiple receivers disposed in the wellbores (for example, the
receiver 114, the receiver 116).
[0022] Each transmitter can be connected to or can include a respective transmitting antenna
(for example, a transmitting antenna 206 connected to the transmitter 106, a transmitting
antenna 208 connected to the transmitter 108, other transmitting antennas connected to
respective transmitters). Similarly, each receiver can be connected to or can include a
respective receiving antenna (for example, a receiving antenna 210 connected to the receiver
118, a receiving antenna 212 connected to the receiver 120, other receiving antennas
connected to respective receivers). In some implementations (including the partial
compensation and full compensation implementations), the control system 200 can cause the
one or more transmitting antennas to produce EM excitation signals in the surrounding
formations, for example, using the transmitter unit 202. The control system 200 can cause
the one or more receiving antennas to receive the EM excitation signals produced by the
multiple transmitting antennas, for example, using the receiver unit 204. The EM signals
received by the receiving antennas are affected by properties of the formation in which the
transmitters and the receivers are disposed. The excitation signals for the transmitting
antennas can be single frequency or broad-band. For broad-band excitations, receivers can
record the time domain signals and compute the associated frequency domain signals via
Fourier transform.
[0023] The control system 200, which is connected to the multiple transmitters and the
multiple receivers, can receive the multiple signals, each of which is or is a representation of
each signal received by each transmitter from each receiver. For example, the control system
200 can receive each signal as a complex voltage. The control system 200 can store the
multiple signals in a computer-readable storage medium (for example, the computer-readable
medium 222). The control system 200 can implement partial compensation or full
compensation techniques (described below) on the multiple signals resulting in multiple
compensated signals. The control system 200 can store the multiple compensated signals in
the computer-readable storage medium. The control system 200 can process the multiple
compensated signals to determine a position of the first wellbore (for example, the wellbore
110) relative to the second wellbore (for example, the wellbore 122), and provide the position
the position, for example, to a display device (not shown) connected to the control system
200.
[0024] In full compensation implementations, the control system 200 can implement the
compensation technique based on EM signals transmitted by at least two transmitters and
received by at least two receivers. To do so, from the signals exchanged by the at least two
transmitters and the at least two receivers, the control system 200 can determine multiple
compensated signals. The control system 200 can determine at least one compensated signal
from a first signal received from a first wellbore and a second signal received from a second
wellbore. Each of the transmitters and the receivers provides both amplitude and phase
measurements. The control system 200 can measure a value of each EM signal, i.e., measure
an amplitude and phase of each EM signal, for example, by digitizing the signal. In the
example configurations described in FIG. IB, the control system 200 can obtain four
measurements from the two transmitters disposed in the production wellbore and the two
receivers disposed in the injection wellbore - from transmitter 106 to receiver 118, from
transmitter 106 to receiver 120, from transmitter 108 to receiver 118, and from transmitter
108 to receiver 128. The control system 200 can receive the measurements as complex
voltages, each having an amplitude and a phase.
[0025] From these measurements, the control system 200 can obtain an R value, which is a
signal ratio. For example, at a first time instant, the control system 200 can determine a first
product of a value of a first signal transmitted by the transmitter 106 to receiver 118 (TlRl)
and a value of a second signal transmitted by transmitter 108 to receiver 120 (T2R2). At the
first time instant, the control system 200 can also determine a second product of a value of a
third signal transmitted by the transmitter 106 to receiver 120 (T1R2) and a value of a fourth
signal transmitted by the transmitter 108 to receiver 118 (T2R1). The control system 200 can
divide the first product by the second product resulting in a first compensated signal. The R
value, which indicates formation properties, changes over time for ranging applications.
[0026] A compensated signal has the capability of cancelling any multiplicative effects for
transmitters or receivers in the form V "TXRY = CT 'X CR ' YV XRY , where V is the voltage that is
affected by the multiplicative effect on transmitter X (CTX) and is the ideal measurement
with no effects. When the control system 200 determines the four term ratio of the signals as
described above, multiplicative effects cancel out as shown below:
[0027] Similarly, to operations performed at the first time instant, at a second time instant,
the control system 200 can determine a third product of a value of a fifth signal transmitted
by the transmitter 106 and received by the receiver 118 and a value of a sixth signal
transmitted by the transmitter 108 and received by the receiver 120. At the second time
instant, the control system 200 can determine a fourth product of a value of a seventh signal
transmitted by the transmitter 106 and received by the receiver 120 and a value of an eighth
signal transmitted by the transmitter 108 and received by the receiver 118. The control
system 200 can divide the third product by the fourth product resulting in a second
compensated signal. In this manner, the control system 200 can take a difference in time to
obtain a time-lapse measurement, for example, between the first time instant and the second
time instant.
[0028] Between the first time instant and the second time instant, the multiple transmitters
and the multiple receivers can be stationary. Alternatively, either the multiple transmitters or
the multiple receivers (or both) can be moved between the first time instant and the second
time instant. A decision to move the transmitters or receivers (or both) or keep the
transmitters or receivers (or both) stationary can depend on a length of the wellbore (for
example, the injection wellbore) that has been drilled between the first time instant and the
second time instant. For example, if the multiple receivers are affixed to the MWD tool,
which is moved as the wellbore is being drilled, then the multiple receivers can move
between the first time instant and the second time instant. If an angle (described above)
formed by the multiple receivers with a transmitter no longer satisfies the threshold after the
MWD tool has moved, then the transmitters can also be moved.
[0029] In some implementations, at the instant that the control system 200 causes the
transmitters to transmit the EM signals and the receivers to receive the EM signals, the
receivers and the transmitters can be stationary. Alternatively, either one or more of the
transmitters or one or more of the receivers (or both) can be mobile during EM signal
transmission and reception. In this manner, the control system 200 can receive the multiple
signals from multiple first locations of the transmitters and the receivers, and multiple other
signals from multiple second locations to which the multiple transmitters and the multiple
receivers are moved in the wellbores.
[0030] The control system 200 records the compensated signal as a function of time. In
general, a function / can be used before the subtraction as shown below:
V" V "
' V " V *
T\R2 1R
S(t ,t )=f{R(t ))- f{R(t )
[0031] In partial compensation implementations, the control system 200 can implement the
compensation technique based on EM signals exchanged between at least one transmitter, at
least one receiver, and either a transmitter or a receiver. In implementations with two
transmitters and a receiver, two measurements are possible - from transmitter 172 to receiver
178 (T1R1) and from transmitter 174 to receiver 178 (T2R1). In implementations with two
receivers and a transmitter, two measurements are possible - from transmitter 152 to receiver
156 (T1R1) and from transmitter 152 to receiver 158 (T1R2). The control system 200 can
receive the EM signals are complex voltages, each having a respective amplitude and a phase.
In the example with two transmitters and one receiver, to determine an R (ratio) value, the
control system 200 can divide a value (i.e., a voltage value) of a first signal transmitted by
transmitter 172 to receiver 178 (TlRl) by a value of a second signal transmitted by
transmitter 174 to receiver 178 (T2R1). When the control system 200 takes the two term
ratio of the signals, multiplicative effects cancel out as shown below, resulting in a first
compensated signal:
T>R (-t \ _
[0032] The control system 200 can implement the afore-described partial compensation
techniques at a first time instant. At a second time instant, the control system 200 can divide
a value of a third signal transmitted by transmitter 172 to receiver 178 by a value of a fourth
signal transmitted by transmitter 174 to receiver 178. The control system 200 can divide the
third signal by the fourth signal resulting in a second compensated signal. The R value,
which indicates formation properties, changes over time for ranging applications. Partially
compensated signal has the capability of canceling any multiplicative effects for either
transmitters in the following form:
v " = v '
[0033] In the equation above, V is the voltage that is affected by the multiplicative effect on
transmitter X (CTX) and is the ideal measurement with no effects.
[0034] Similarly, in the example with two receivers and one transmitter, to determine an R
(ratio) value, the control system 200 can divide a first signal transmitted by transmitter 152 to
receiver 156 (TlRl) by a value of a second signal transmitted by transmitter 152 to receiver
158 (T1R2). When the control system 200 takes the two term ratio of the signals,
multiplicative effects cancel out as shown below:
f t f t f t
( f TlRl _ ffl ' ii _ ffl' r
t f t f t f t
* TlRl T Rl ' TlRl Rl* TlRl
[0035] The control system 200 can implement the afore-described partial compensation
techniques at a first time instant. At a second time instant, the control system 200 can divide
a value of a third signal transmitted by transmitter 152 to receiver 156 by a value of a fourth
signal transmitted by transmitter 152 to receiver 158. Similarly to full compensation, the
received signal, in partial compensation, can be recorded as a function of time, and a
difference in time can be taken to obtain a time-lapse measurement.
S t ,t )=f{R(t ))-f{R(t ))
[0036] In this equation, R can be uncompensated, partially compensated or fully
compensated depending on the type of compensation technique that the control system 200
implements. One example of the function / is the identity function, i.e., f(x) =x . Another
example for the function /is the logarithmic function, which makes Sindicate the logarithmic
change in the signal levels between the first time instant (i.e., t ) and the second time instant
(i.e., ti). Other examples of the function / are also possible. Further, in some
implementations, the control system 200 can determine a second difference of measurements
at three time instants.
[0037] In some implementations, the control system 200 can be connected to a data
acquisition unit 214 to receive signals received by the control system 200 from the receiver
unit 204. As an alternative or in addition to storing the signals in the computer-readable
medium 222, the signals can be stored in a data buffer 216 connected to the control system
200 and the data acquisition unit 214. The processor (for example, a data processing
apparatus 218) can be implemented as a component of the control system 200 or can reside
external to the control system 200 (or both). To provide the position of the first wellbore
relative to the second wellbore, for example, to a display device at the surface, the control
system 200 can be connected to a communication unit 220, which can transmit data using
either wired or wireless networks (or both). For example, the communication unit 220 can be
implemented as a telemetry system.
[0038] In the example operations described with reference to the control system 200, the
compensation technique is implemented as computer operations. Alternatively or in addition,
the compensation technique can be implemented using hardware or firmware. For example,
the ratios used in the compensation technique can be calculated by hardware by measuring
phase difference and attenuation between the receivers instead of (or in addition to)
measuring the absolute signals. Additional time-lapse processing can also be applied on the
compensated signal. The control system 200 can be implemented down hole or at the
surface.
[0039] FIG. 3 is an example of a preprocessing unit for preprocessing electromagnetic signals
before partial compensation or full compensation. As shown in FIG. 3, the control system
200 can include multiple components for preprocessing, each of which can be implemented
as a computer-readable medium storing instructions executable by the processor (for
example, the data processing apparatus 218). In some implementations, the control system
200 can implement preprocessing techniques on the multiple signals received from the one or
more transmitters before implementing the compensation techniques. For example, a first
preprocessing unit 304 can receive sensor data from multiple sources (i.e., the transmitters) at
time ti, i.e., the first time instant. A second preprocessing unit 302 can receive sensor data
from multiple sources (i.e., the transmitters) at time ¾ i.e., the second time instant. In some
implementations, a compensated signal calculation unit 306 can implement resistivity logging
signal processing techniques, for example, multi-component synthesis, differential signal
synthesis, virtual arrays created from depth/time delayed data, or combinations of them. The
preprocessing can include filtering with respect to time or depth to improve signal to noise
ratio. The preprocessing can additionally include multi-array synthesis by combining
information from different sensor positions. The preprocessing can also include azimuthal
binning and multi-bin processing to obtain dipole tensor components as well known in
Logging While Drilling propagation induction resistivity well logging. Preprocessing can
also include calibration operation utilizing past measurements or predicted position (or both)
of moving sensor system or environmental conditions.
[0040] Alternatively, or in addition, the control system 200 can implement an inversion unit
308 based on the compensated signal via forward modeling (for example, that uses a forward
model 310) and feedback (for example, that uses a library 312). The inversion units accept
the compensated signals as the input and outputs pipe or environmental parameters such as
pipe distance and direction, transmitter location, receiver location, environmental parameters,
and the like. Based on the difference between input signals and the modeling result, variable
set of output parameters can be adjusted to reduce the difference. The afore-described
operations can be iterated and stopped once the difference reduces satisfies a threshold.
Alternatively, or in addition, a look-up table that maps the input to output parameters can be
computed and used. Parameters including pipe distance and direction, transmitter location,
wellbore size, and other environmental parameters can be obtained by implementing
preprocessing.
[0041] FIGS. 4A and 4B are plots comparing compensated and uncompensated
electromagnetic signals. The electromagnetic signals received by the receivers are used to
determine the distance between the two wellbores in which the transmitters and the receivers
are disposed. In the case of no time-lapse signal measurement, a high signal can indicate that
the wells are close and a low signal can indicate that the wells are far apart. In the case of
time-lapse signal measurement, a high signal can indicate that the wells are getting closer and
a low signal can indicate that the separation between the wells is increasing. The inversion
process described above can be the basis on which the interpretation of closeness from the
compensated signals is made. The plots shown in FIGS. 4A and 4B are determined by
ranging in the SAGD application. Plot 402 is a plot of time-lapsed attenuation versus time
for measured compensated signals, true compensated signals, measured uncompensated
signals, and true uncompensated signals. Plot 404 is a plot of time-lapse phase versus time
for measured compensated signals, true compensated signals, measured uncompensated
signals, and true uncompensated signals. The produced signal is used to determine the
position of the receivers or equivalently the tool body with respect to a reference such as a
location in the injector or producer wells, or a previously known position of the receiver.
Although the receiver is moving in this example, the transmitter could alternatively or in
addition be moving. In this example, an amplitude drift and phase draft is used on all of the
receivers. The plots show that, despite the draft, the compensated measurement is not
affected from phase shifts whereas uncompensated measurements are affected.
[0042] FIG. 5 is a flowchart of an example process 500 for ranging from multiple wellbores
implementing full compensation. The process 500 can be implemented as computer
instructions stored on computer-readable media (for example, the computer-readable medium
222) and executable by the processor (for example, data processing apparatus 218). For
example, the process 500 can be implemented by the control system 200. At 502, multiple
signals are received. Each signal corresponds to an electromagnetic signal received by a
receiver of multiple receivers corresponds to an electromagnetic signal received by a receiver
of multiple receivers disposed in multiple wellbores from a transmitter of multiple
transmitters disposed in the multiple wellbores.
[0043] At 504, full compensation techniques are implemented on the multiple signals
resulting in multiple compensated signals. For example, from the received multiple signals,
multiple compensated signals can be determined. At least one compensated signal can be
determined from a first signal received from a first wellbore and a second signal received
from a second wellbore of the plurality of wellbores. At 506, the multiple compensated
signals are processed to determine a position of a first wellbore of the multiple wellbores
relative to a second wellbore of the multiple wellbores. At 508, the position of the first
wellbore relative to the second wellbore is provided.
[0044] FIG. 6 is a flowchart of an example process 600 for ranging from multiple wellbores
implementing partial compensation. The process 600 can be implemented as computer
instructions stored on computer-readable media (for example, the computer-readable medium
222) and executable by the processor (for example, the data processing apparatus 218). For
example, the process 500 can be implemented by the control system 200. At 602, multiple
signals are received. Each signal corresponds to an electromagnetic signal exchanged by a
first transmitter disposed in a first wellbore to transmit electromagnetic signals, a first
receiver disposed in a second wellbore to receive the electromagnetic signals transmitted by
the first transmitter, and either a second transmitter or a second receiver. The second
transmitter or the second receiver can be disposed in either the first wellbore or in the second
wellbore or in a location other than the wellbore (for example, at the surface).
[0045] At 604, partial compensation techniques are implemented on the multiple signals
resulting in multiple compensated signals. At 606, the multiple compensated signals are
processed to determine a position of a first wellbore of the multiple wellbores relative to a
second wellbore of the multiple wellbores. At 608, the position of the first wellbore relative
to the second wellbore is provided.
[0046] A number of embodiments have been described. Nevertheless, it will be understood
that various modifications may be made without departing from the spirit and scope of the
invention.

WHATIS CLAIMED IS
1.A system for ranging in wellbores, the system comprising:
a plurality of transmitters disposed in a plurality of wellbores, each transmitter to
transmit electromagnetic signals;
a plurality of receivers disposed in the plurality of wellbores, each receiver to
receive the electromagnetic signals transmitted by the plurality of transmitters; and
a processor connected to the plurality of transmitters and the plurality of
receivers, the processor configured to:
receive a plurality of signals from the plurality of receivers as sent by the
plurality of transmitters,
from the received plurality of signals, determine a plurality of
compensated signals, at least one compensated signal determined from a first signal
received from a first wellbore of the plurality of wellbores and a second signal received
from a second wellbore of the plurality of wellbores,
process the plurality of compensated signals to determine a position of the
first wellbore of the plurality of wellbores relative to the second wellbore of the plurality
of wellbores, and
provide the position of the first wellbore relative to the second wellbore.
2. The system of claim 1, wherein the first wellbore is a pre-existing production wellbore,
and wherein either the plurality of receivers or the plurality of transmitters or a
combination of at least one receiver and at least one transmitter are disposed in the
production wellbore.
3. The system of claim 2, wherein either the plurality of receivers or the plurality of
transmitters or a combination of at least one receiver and at least one transmitter are
spaced apart and affixed to one or more portions of casings disposed within the
production wellbore.
4. The system of claim 1, wherein the second wellbore is a steam-assisted gravity
drainage (SAGD) wellbore being drilled, and wherein either the plurality of receivers or
the plurality of transmitters or a combination of at least one receiver and at least one
transmitter are disposed in the SAGD wellbore.
5. The system of claim 4, further comprising a measurement while drilling (MWD) tool
disposed in the SAGD wellbore, wherein either the plurality of receivers or the plurality
of transmitters or a combination of at least one receiver and at least one transmitter are
affixed to the MWD tool.
6. The system of claim 4, wherein either the plurality of receivers or the plurality of
transmitters or a combination of at least one receiver and at least one transmitter are
spaced apart by a distance ranging between 2 feet and 50 feet.
7. The system of claim 1, wherein the first wellbore and the second wellbore are either
substantially parallel to each other or substantially perpendicular to each other.
8. The system of claim 1, wherein the plurality of transmitters includes a first transmitter
and the plurality of receivers includes a first receiver and a second receiver, and wherein
the first transmitter, the first receiver and the second receiver are disposed in the plurality
of wellbores such that an angle formed by a first line connecting the first receiver and the
first transmitter and a second line connecting the second receiver and the first transmitter
satisfies a threshold angle.
9. The system of claim 8, wherein the threshold angle is at least 5 degrees.
10. The system of claim 1, wherein the processor is further configured to measure a value
of each of the plurality of signals as a complex voltage.
11. The system of claim 1, wherein the processor is further configured to:
receive the plurality of signals from a first plurality of locations of the plurality of
transmitters and the plurality of receivers in the plurality of wellbores; and
receive another plurality of signals from a second plurality of locations to which
the plurality of transmitters and the plurality of receivers are moved in the plurality of
wellbores.
12. The system of claim 1, further comprising a computer-readable storage medium to
store the plurality of signals and the plurality of compensated signals.
13. The system of claim 1, wherein, to determine the plurality of compensated signals,
the processor is configured, at a first time instant, to:
determine a first product of a value of a first signal transmitted by a first
transmitter and received by a first receiver, and a value of a second signal transmitted by
a second transmitter and received by a second receiver;
determine a second product of a value of a third signal transmitted by the first
transmitter and received by the second receiver, and a value of a fourth signal transmitted
by the second transmitter and received by the first receiver; and
divide the first product by the second product resulting in a first compensated
signal.
14. The system of claim 13, wherein the processor is further configured, at a second time
instant, to:
determine a third product of a value of a fifth signal transmitted by the first
transmitter and received by the first receiver, and a value of a sixth signal transmitted by
the second transmitter and received by the second receiver;
determine a fourth product of a value of a seventh signal transmitted by the first
transmitter and received by the second receiver, and a value of an eighth signal
transmitted by the second transmitter and received by the first receiver; and
divide the third product by the fourth product resulting in a second compensated
signal.
15. The system of claim 14, wherein the processor is further configured to:
record the first compensated signal and the second compensated signal as a first
function of time and a second function of time, respectively; and
obtain a time-lapse measurement between the first instant and the second instant.
16. The system of claim 15, wherein, to obtain the time-lapse measurement between the
first instant and the second instant, the processor is configured to:
apply a logarithmic function to the first function of time;
apply a logarithmic function to the second function of time; and
determine a difference between the logarithmic function applied to the first
function of time and the logarithmic function applied to the second function of time.
17. The system of claim 14, wherein the plurality of transmitters and the plurality of
receivers are stationary during the first time instant and the second time instant.
18. The system of claim 14, wherein either the plurality of transmitters or the plurality of
receivers is mobile during either the first time instant or the second time instant.
19. The system of claim 1, wherein the processor is further configured to implement
preprocessing techniques on the plurality of signals before implementing the
compensation techniques.
20. A system for ranging in wellbores, the system comprising:
a first transmitter disposed in a first wellbore to transmit electromagnetic signals;
a first receiver disposed in a second wellbore to receive the electromagnetic
signals transmitted by the first transmitter;
either a second transmitter or a second receiver disposed in either the first
wellbore or the second wellbore to communicate electromagnetic signals with the first
transmitter or the first receiver; and
a processor connected to the first transmitter, the first receiver, and either the
second transmitter or the second receiver, the processor configured to:
receive a plurality of signals communicated by the first transmitter, the
first receiver, and either the second transmitter or the second receiver, wherein the
plurality of signals includes a signal that corresponds to an electromagnetic signal
received by the first receiver from the first transmitter;
implement compensation techniques on the plurality of signals resulting in
a plurality of compensated signals;
process the plurality of compensated signals to determine a position of a
first wellbore of the plurality of wellbores relative to a second wellbore of the plurality of
wellbores; and
provide the position of the first wellbore relative to the second wellbore.
21. The system of claim 20, comprising the second transmitter disposed in the first
wellbore to transmit electromagnetic signals, wherein the first receiver is disposed in the
second wellbore to receive the electromagnetic signals transmitted by the second
transmitter, and wherein the processor is further configured to receive a signal that
corresponds to an electromagnetic signal received by the first receiver from the second
transmitter.
22. The system of claim 21, wherein the processor is further configured, at a first time
instant, to divide a value of a first signal transmitted by the first transmitter and received
by the first receiver by a value of a second signal transmitted by the second transmitter
and received by the first receiver resulting in a first compensated signal.
23. The system of claim 21, wherein the processor is further configured, at a second time
instant, to divide a value of a third signal transmitted by the first transmitter and received
by the first receiver by a value of a fourth signal transmitted by the second transmitter
and received by the first receiver resulting in a second compensated signal.
24. The system of claim 23, wherein the processor is further configured to:
record the first compensated signal and the second compensated signal as a first
function of time and a second function of time, respectively; and
obtain a time-lapse measurement between the first instant and the second instant.
25. The system of claim 24, wherein, to obtain the time-lapse measurement, the processor
is configured to:
apply a logarithmic function to the first function of time;
apply a logarithmic function to the second function of time; and
determine a difference between the logarithmic function applied to the first
function of time and the logarithmic function applied to the second function of time.
26. The system of claim 20, comprising the second receiver disposed in the second
wellbore to receive the electromagnetic signals transmitted by the first transmitter, and
wherein the processor is further configured to receive a signal that corresponds to an
electromagnetic signal received by the second receiver from the first transmitter.
27. The system of claim 26, wherein the processor is further configured to divide a value
of a third signal transmitted by the first transmitter and received by the first receiver by a
value of a fourth signal transmitted by the first transmitter and received by the second
receiver resulting in a second compensated signal.
28. The system of claim 26, wherein the first wellbore is a steam-assisted gravity
drainage (SAGD) wellbore being drilled, and wherein either the first receiver or the first
transmitter or the second receiver or the second transmitter is disposed in the SAGD
wellbore.
29. The system of claim 28, wherein the second wellbore is a pre-existing production
wellbore, and wherein either the first receiver or the first transmitter or the second
receiver or the second transmitter is disposed in the pre-existing production wellbore.
30. The system of claim 26, further comprising a measurement while drilling (MWD)
tool in the SAGD wellbore, wherein a combination including at least two of the first
receiver, the first transmitter, the second receiver, or the second transmitter are affixed to
and spaced apart on the MWD tool.
31. The system of claim 26, wherein the processor is further configured to measure a
value of each of the plurality of signals as a complex voltage.
32. The system of claim 26, wherein the processor is configured to:
receive the plurality of signals received by the first receiver and the second
receiver disposed at a first location and a second location, respectively, within the second
wellbore from the first transmitter disposed at a third location within the first wellbore;
and
receive another plurality of signals received by the first receiver and the second
receiver moved to a fourth location and a fifth location, respectively, within the second
wellbore from the first transmitter disposed at the third location.
33. The system of claim 20, further comprising a computer-readable storage medium to
store the plurality of signals and the compensated plurality of signals.
34. A computer-readable medium storing instructions executable by a processor to
perform operations for ranging in wellbores, the operations comprising:
receiving a plurality of signals from a plurality of transmitters disposed in a
plurality of wellbores to transmit electromagnetic signals and a plurality of receivers
disposed in the plurality of wellbores to receive the electromagnetic signals transmitted
by the plurality of transmitters, wherein each signal of the plurality of signals is received
by each transmitter from each receiver,
from the received plurality of signals, determining a plurality of compensated
signals, at least one compensated signal determined from a first signal received from a
first wellbore of the plurality of wellbores and a second signal received from a second
wellbore of the plurality of wellbores,
processing the plurality of compensated signals to determine a position of a first
wellbore of the plurality of wellbores relative to a second wellbore of the plurality of
wellbores, and
providing the position of the first wellbore relative to the second wellbore.
35. A method for ranging in wellbores, the method comprising:
receiving, by a processor, a plurality of signals from a plurality of transmitters
disposed in a plurality of wellbores to transmit electromagnetic signals and a plurality of
receivers disposed in the plurality of wellbores to receive the electromagnetic signals
transmitted by the plurality of transmitters, wherein each signal of the plurality of signals
is received by each transmitter from each receiver,
from the received plurality of signals, determining, by the processor, a plurality of
compensated signals, at least one compensated signal determined from a first signal
received from a first wellbore of the plurality of wellbores and a second signal received
from a second wellbore of the plurality of wellbores,
processing, by the processor, the plurality of compensated signals to determine a
position of a first wellbore of the plurality of wellbores relative to a second wellbore of
the plurality of wellbores, and
providing, by the processor, the position of the first wellbore relative to the
second wellbore.
36. A computer-readable medium storing instructions executable by a processor to
perform operations for ranging in wellbores, the operations comprising:
receiving a plurality of signals communicated between a first transmitter disposed
in a first wellbore to transmit electromagnetic signals, a first receiver disposed in a
second wellbore to receive the electromagnetic signals transmitted by the first transmitter,
and either a second transmitter or a second receiver disposed in either the first wellbore
or the second wellbore to communicate electromagnetic signals with the first transmitter
or the first receiver, wherein the plurality of signals includes a signal that corresponds to
an electromagnetic signal received by the first receiver from the first transmitter;
implementing compensation techniques on the plurality of signals resulting in a
compensated plurality of signals;
processing the compensated plurality of signals to determine a position of a first
wellbore of the plurality of wellbores relative to a second wellbore of the plurality of
wellbores; and
providing the position of the first wellbore relative to the second wellbore.
37. A method for ranging in wellbores, the method comprising:
receiving, by a processor, a plurality of signals communicated between a first
transmitter disposed in a first wellbore to transmit electromagnetic signals, a first receiver
disposed in a second wellbore to receive the electromagnetic signals transmitted by the
first transmitter, and either a second transmitter or a second receiver disposed in either the
first wellbore or the second wellbore to communicate electromagnetic signals with the
first transmitter and the first receiver, wherein the plurality of signals includes a signal
that corresponds to an electromagnetic signal received by the first receiver from the first
transmitter;
implementing, by the processor, compensation techniques on the plurality of
signals resulting in a compensated plurality of signals;
processing, by the processor, the compensated plurality of signals to determine a
position of a first wellbore of the plurality of wellbores relative to a second wellbore of
the plurality of wellbores; and
providing, by the processor, the position of the first wellbore relative to the
second wellbore.