U.S. patent application number 13/002753 was filed with the patent office on 2012-03-22 for system and method for using a resistivity tool with wired drill pipe and one or more wells.
Invention is credited to Anthony N. Krepp, Emmanuel Legendre, Richard J. Meehan, Michael A. Montgomery, Jean Seydoux, Eric Tabanou, Jacques R. Tabanou, Reza Taherian.
Application Number | 20120068712 13/002753 |
Document ID | / |
Family ID | 41507706 |
Filed Date | 2012-03-22 |
United States Patent
Application |
20120068712 |
Kind Code |
A1 |
Taherian; Reza ; et
al. |
March 22, 2012 |
SYSTEM AND METHOD FOR USING A RESISTIVITY TOOL WITH WIRED DRILL
PIPE AND ONE OR MORE WELLS
Abstract
A resistivity tool is used with wired drill pipe and one or more
wells. The resistivity tool has a transmitter, receiver modules
located adjacent to the drill bit, and high sensitivity receiver
modules located at greater distances from the drill bit relative to
the receiver modules. The receiver modules and/or the high
sensitivity receiver modules may also perform repeater functions
for the wired drill pipe. The resistivity tool may provide
information regarding a subsurface region of interest. The
resistivity tool may be used in a system with sensors, and a
distance between the sensors may be based on the type of
measurement obtained by the sensors.
Inventors: |
Taherian; Reza; (Sugar Land,
TX) ; Tabanou; Jacques R.; (Houston, TX) ;
Legendre; Emmanuel; (Houston, TX) ; Meehan; Richard
J.; (Sugar land, TX) ; Krepp; Anthony N.; (The
Woodlands, TX) ; Montgomery; Michael A.; (Sugar Land,
TX) ; Seydoux; Jean; (Rio de Janeiro, Ry, BR)
; Tabanou; Eric; (Houston, TX) |
Family ID: |
41507706 |
Appl. No.: |
13/002753 |
Filed: |
July 10, 2009 |
PCT Filed: |
July 10, 2009 |
PCT NO: |
PCT/US2009/050306 |
371 Date: |
December 6, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61079681 |
Jul 10, 2008 |
|
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|
Current U.S.
Class: |
324/338 |
Current CPC
Class: |
G01V 1/48 20130101; G01V
2210/614 20130101; G01V 1/282 20130101 |
Class at
Publication: |
324/338 |
International
Class: |
G01V 3/00 20060101
G01V003/00 |
Claims
1. A system to measure a resistivity of a subsurface formation
comprising: a transmitter module having at least one antenna; one
or more sections of wired drill pipe in communication with the
transmitter module; and a first receiver module having at least one
antenna and in communication with the one or more sections of wired
drill pipe, wherein the receiver module and the transmitter module
are separated by the one or more section of wired drill pipe.
2. The system of claim 1 wherein at least one of the transmitter
module and the first receiver module is incorporated into a
telemetry repeater in communication with the one or more sections
of wired drill pipe.
3. The system of claim 1 wherein at least one of the transmitter
module and the first receiver module performs the functions of a
telemetry repeater for signals transmitted via the one or more
sections of wired drill pipe.
4. The system of claim 1 wherein a distance between the transmitter
module and the first receiver module is based on a depth of
investigation.
5. The system of claim 1 wherein the first receiver module is
located at a distance in excess of 100 feet from the transmitter
module.
6. The system of claim 5 wherein the first receiver module is
separated from the transmitter module by at least three sections of
wired drill pipe.
7. The system of claim 1 further comprising a first clock
associated with the transmitter module and a second clock
associated with the fist receiver module wherein the first clock
and the second clock are synchronized via data transmitted via the
one or more sections of wired drill pipe.
8. The system of claim 1 wherein the transmitter module and the
first receiver module provide data indicative of a position of a
first wellbore relative to a second wellbore.
9. The system of claim 1 wherein the at least one antenna of the
transmitter module or the first receiver module is tilted with
respect to an axis extending through a length of the transmitter
module.
10. The system of claim 1 wherein the at least one antenna of the
transmitter module is axial or parallel to an axis extending
through a length of the transmitter module.
11. The method of claim 1 wherein bending of the wired drill pipe
varies the depth of investigation of the transmitter module and the
first receiver module.
12. A system for making a subsurface measurement comprising: a
drill string comprising a plurality of wired drill pipes having a
communication channel, the drill string extending into a subsurface
formation; a plurality of sensors distributed at distances along
the drill string wherein the distances between the plurality of
sensors is determined from an equation; and wherein the plurality
of sensors are in communication with the wired drill pipes.
13. The system of claim 12 wherein at least one of the sensors is
located at a telemetry repeater in communication with the plurality
of wired drill pipes, and further wherein the telemetry repeater
amplifies a signal transmitted along the plurality of wired drill
pipes.
14. The system of claim 12 wherein the equation is a linear
equation.
15. The system of claim 12 wherein the equation is a exponential
equation.
16. The system of claim 12 wherein the equation is a logarithmical
equation.
17. The system of claim 12 wherein the plurality of sensors are
equally spaced along the drill string.
18. The system of claim 12 wherein the equation describes
dependence of subsurface measurement on an independent variable in
a linear, inverse, logarithmical, exponential, or a power law
fashion.
19. The system of claim 12 wherein the plurality of sensors measure
a characteristic of a formation surrounding the drill string.
20. The system of claim 12 wherein the plurality of sensors measure
a characteristic of the drill string.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention generally relates to a system and a
method for using a resistivity tool with a telemetry system, such
as wired drill pipe, in one or more wellbores. More specifically,
the present invention relates to a resistivity tool having a
transmitter, receiver modules located adjacent to the drill bit,
and high sensitivity receiver modules located at distances from the
drill bit relative greater than the receiver modules. The receiver
modules and/or the high sensitivity receiver modules may also
perform repeater functions for the wired drill pipe. The
resistivity tool may provide information regarding a subsurface
region of interest.
[0002] To obtain hydrocarbons, a drilling tool is driven into the
ground surface to create a wellbore through which the hydrocarbons
are extracted. Typically, a drill string is suspended within the
wellbore. The drill string has a drill bit at a lower end of the
drill string. The drill string extends from the surface to the
drill bit. The drill string has a bottom hole assembly (BHA)
located proximate to the drill bit.
[0003] Measurements of drilling conditions, such as, for example,
an inclination and an azimuth, a drift of the drill bit, fluid flow
rates and fluid composition, may be necessary for adjustment of
operating parameters, such as, for example, a trajectory of the
wellbore, flow rates, wellbore pressures, rate of penetration,
weight on bit and the like. The BHA has tools that may generate
and/or may obtain the measurements of the drilling conditions. For
example, the BHA may acquire information regarding the wellbore and
subsurface formations. Technology for transmitting information
within a wellbore, known as telemetry technology, is used to
transmit the information from the tools of the BHA to the surface
for analysis. The information may be used to control the tools.
Adjustment of the drilling operations in response to accurate
real-time information regarding the tools, the wellbore, the
formations and the drilling conditions may enable optimization of
the drilling process to increase a rate of penetration of the drill
bit, reduce a drilling time and/or optimize a placement of the
wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1 illustrates a drill string having a resistivity tool
in an embodiment of the present invention.
[0005] FIG. 2 illustrates a drill string and a point of interest in
a formation in an embodiment of the present invention.
[0006] FIG. 3 illustrates a box diagram of a drill string having
repeaters positioned between a bottom hole assembly and a surface
system or terminal in an embodiment of the present invention.
[0007] FIG. 4 illustrates a portion of a drill string with a
transmitter module and a receiver module in an embodiment of the
present invention.
[0008] FIG. 5 illustrates two wellbores where one of the wells
substantially encircles a formation of interest in an embodiment of
the present invention.
[0009] FIG. 6 illustrates two wellbores where one of the wellbores
is positioned around a formation of interest in an embodiment of
the present invention.
[0010] FIG. 7 illustrates areas of position uncertainty around two
drilled wells in an embodiment of the present invention.
[0011] FIG. 8 illustrates a modular resistivity tool determining a
position of a first well relative to a second well in an embodiment
of the present invention.
[0012] FIG. 9 illustrates a modular resistivity tool used for
avoiding collision between two wells in an embodiment of the
present invention.
[0013] FIG. 10 illustrates a modular resistivity tool used for
intercepting a first well with a second well in an embodiment of
the present invention.
[0014] FIGS. 11A and 11B illustrate the effect of a cased well on
the measurement of a modular resistivity tool in an embodiment of
the present invention.
[0015] FIG. 12 illustrates a repeater having a receiver and a
transmitter in an embodiment of the present invention.
[0016] FIG. 13 illustrates a repeater connected to a wired drill
string in an embodiment of the present invention.
[0017] FIG. 14 illustrates different responses of sensors versus
time or depth in an embodiment of the present invention.
[0018] FIG. 15 illustrates an optimum sensor-sensor spacing for
different functions in an embodiment of the present invention.
[0019] FIG. 16 illustrates a drilling assembly with sensors spacing
optimum for square root of time dependence in an embodiment of the
present invention.
[0020] FIG. 17 illustrates a drilling assembly with sensors spacing
optimum for linear time dependence in an embodiment of the present
invention.
[0021] FIG. 18 illustrates the absolute and relative measurements
in an embodiment of the present invention.
[0022] FIG. 19 illustrates the bottom hole assembly with one
transmitter and two receiver modules that can be used for absolute
and relative measurements in an embodiment of the present
invention.
[0023] FIG. 20 illustrates a module with two tilted antennas in an
embodiment of the present invention.
[0024] FIG. 21 illustrates the drilling assembly with high
sensitivity receiver modules that can be used for absolute and
relative measurements in an embodiment of the present
invention.
[0025] FIG. 22 illustrates a module with tilted antennas for
measuring +z and -z components of the signal in an embodiment of
the present invention.
DETAILED DESCRIPTION OF THE PRESENTLY PREFERRED EMBODIMENTS
[0026] The invention is described with reference to figures that
display embodiments of the invention. None of the drawings or
description with reference to the figures is meant to limit the
invention to these embodiments. The invention should be given its
broadest interpretation and should only be limited by the
claims.
[0027] The present invention generally relates to a system and a
method for using a resistivity tool in conjunction with wired drill
pipe. More specifically, the present invention relates to a
resistivity tool having a transmitter module and a first receiver
module located adjacent to the drill bit and a second receiver
module located at a greater distance from the drill bit relative to
the first receiver module. An acoustic impedance of a formation
layer may be determined using the resistivity tool and the results
may be used to improve drilling decisions or locate features not
detectable by conventional resisitivity tools. The receiver modules
may also perform repeater functions for the wired drill pipe. The
resistivity tool may provide information regarding a subsurface
region of interest. Sensors that obtain a measurement may be spaced
from each other based on the dependence of the measurement on an
independent variable.
[0028] Referring to FIG. 1, measurements may be provided by a
bottom hole assembly 10 (hereafter "the BHA 10") of a drill string
14 extending into a wellbore 30. The measurements may enable
determination of the depths of boundaries separating adjacent
subsurface formation layers. For example, the BHA 10 may comprise
one or more tools measuring characteristics of the wellbore, the
formation around the wellbore, and/or the drill string 20. For
example, the BHA 10 may comprise one or a plurality of known types
of telemetry, survey or measurement tools, such as,
logging-while-drilling tools (hereinafter "LWD tools"),
measuring-while-drilling tools (hereinafter "MWD tools"), near-bit
tools, on-bit tools, and/or wireline configurable tools.
[0029] The LWD tools may include capabilities for measuring,
processing, and storing information, as well as for communicating
with surface equipment. Additionally, the LWD tools may include one
or more of the following types of logging devices that measure
formation characteristics: a resistivity measuring device; a
directional resistivity measuring device; a sonic measuring device;
a nuclear measuring device; a nuclear magnetic resonance measuring
device; a pressure measuring device; a seismic measuring device; an
imaging device; a formation sampling device; a natural gamma ray
device; a density and photoelectric index device; a neutron
porosity device; and the wellbore 30 caliper device.
[0030] The MWD tools may include one or more devices for measuring
characteristics of the drill string 20, providing or generating
power, providing communication to or from the BHA 10, measuring
characteristics of the wellbore or formation surrounding the
wellbore, such as measuring a direction or inclination of the
wellbore, and other measurements known to those having ordinary
skill in the art. For example, the MWD tools may include one or
more of the following types of measuring devices: a weight-on-bit
measuring device; a torque measuring device; a vibration measuring
device; a shock measuring device; a stick slip measuring device; a
direction measuring device; an inclination measuring device; a
natural gamma ray device; a directional survey device; a tool face
device; the wellbore 30 pressure device; and a temperature
device.
[0031] The wireline configurable tool may be a tool commonly
conveyed by wireline cable as known to one having ordinary skill in
the art. For example, the wireline configurable tool may be a
logging tool for sampling or measuring characteristics of the
formation, such as gamma radiation measurements, nuclear
measurements, density measurements, and porosity measurements.
[0032] The BHA 10 may also have a steering mechanism that may
control a direction of drilling, the rotation of the drill string
14, an inclination of the wellbore and/or an azimuth of the
wellbore. A structural model, known to one having ordinary skill in
the art as a "layer cake model," may be defined using the depths of
the boundaries calculated using the electromagnetic LWD
measurements. The LWD measurements may be resistivity measurements,
density measurements and/or sonic velocity measurements, for
example. The present invention is not limited to a specific
embodiment of the electromagnetic LWD measurements, and the
electromagnetic LWD measurements may be any measurements known to
one having ordinary skill in the art.
[0033] Wired drill pipe 20 may be used to optimize determination of
the depths of the boundaries. An example of the wired drill pipe 20
is described in U.S. Pat. No. 6,641,434 to Boyle et al.
incorporated herein by reference in its entirety. The wired drill
pipe 20 may consist of one or more wired drill pipe joints that may
be interconnected to form at least a portion the drill string
(hereinafter "wired drill string" or "wired drill pipe"). The wired
drill pipe 20 may enable the BHA 10 to communicate with a surface
terminal 5 in substantially real-time. The present invention is not
limited to a specific embodiment of the wired drill pipe 20. In
addition, other telemetry systems or combination of systems may
enable the BHA 10 to communicate with the surface terminal 5 as
known to one having ordinary skill in the art. For example, a
combination of mud pulse telemetry and wired drill pipe may be
used.
[0034] The surface terminal 5 may be, for example, a desktop
computer, a laptop computer, a mobile cellular telephone, a
personal digital assistant ("PDA"), a 4G mobile device, a 3G mobile
device, a 2.5G mobile device, an internet protocol (hereinafter
"IP") video cellular telephone, an ALL-IP electronic device, a
satellite radio receiver and/or the like. The surface terminal 5
may be located at a surface location and/or may be remote relative
to the wellbore 30. The present invention is not limited to a
specific embodiment of the surface terminal 5, and the surface
terminal 5 may be any device that has a capability to communicate
with the BHA 10 using the drill string 14. Any number of surface
terminals may be connected to the drill string 14, and the present
invention is not limited to a specific number of surface
terminals.
[0035] The surface terminal 5 may store, process and analyze the
data transmitted by the drill string 14. The surface terminal 5 may
also generate and transmit control messages to the BHA 10 and/or
other downhole tools. For example, the surface terminal 5 may
automatically generate the control messages based on the data
transmitted by the wired drill pipe 20. As a further example, the
surface terminal 5 may provide the data to an operator that may
consider the data and may transmit the control messages based on
user input.
[0036] The wired drill pipe 20 may be used to optimize the
determination of the depths of the boundaries by controlling
configuration of tools associated with the BHA 10. For example,
spacing and/or frequencies of the tools may be controlled to obtain
optimum detection of the depths of the boundaries.
[0037] FIG. 2 depicts a resistivity tool 40 associated with a drill
string 14 located within the wellbore 30. In the embodiment
depicted in FIG. 2, the resistivity tool 40 has at least one
transmitter module 55 and at least two receiver modules 51 and 52.
In an embodiment, the resistivity tool 40 may have one or more dual
purpose modules that may have a transmitter antenna and a receiver
antenna. Thus, the dual purpose module may act as both a
transmitter and a receiver.
[0038] The transmitter module 55 may have a transmitter antenna to
transmit an electromagnetic signal into a formation F. The
transmitter module 55 may have electronic circuitry to enable
transmission of the electromagnetic signal from the antenna. The
transmitter antenna may be a coil with a number of winding turns.
The transmitter module 55 may be associated with the BHA 10 and/or
may be located proximate to a drill bit 15 of the drill string 14.
The transmitter module 55 may be programmed to transmit the
electromagnetic signal as pulses at a predetermined sequence, such
as, for example, a sequence of time intervals, time duration and/or
frequency. In an alternate embodiment, the transmitter module 55
may be programmed from surface in real time using the wire drill
pipe 20. The electromagnetic signal may include information about
the formation F through which the electromagnetic signal has
traveled before receipt by at least one of the receiver modules 51,
52. The electromagnetic signal may convey information about the
transmitter module 55 and/or the receiver modules 51, 52, such as,
for example, antenna efficiency, a distance between antennas, an
antenna orientation and/or the like.
[0039] The receiver modules 51, 52 may receive the electromagnetic
signal from the transmitter module 55. The receiver module 51 may
be a first distance from a drill bit 15 and the receiver module 52
may be a second distance from the drill bit 15 which may be greater
than the first distance. Each of the receiver modules 51 and 52 may
have at least one receiver antenna that may be a coil having
winding turns. In an embodiment, the receiver antenna of the
receiver modules 51 and 52 may have more winding turns than the
antenna of the transmitter module 55. Each of the receiver modules
51 and 52 may have electronic circuitry to enable the receiver
antenna to receive the electromagnetic signal transmitted from the
transmitter antenna.
[0040] One or more of the receiver modules 51 and 52 may be located
within the BHA 10 at a distance from the transmitter module 55. The
electromagnetic signal received by the receiver modules 51, 52, etc
may be used to determine formation properties at a depth of
investigation that may correspond to the distance from the receiver
module to the transmitter module. The present invention may have
any number of transmitter modules 55 and receiver modules 51, 52,
and the present invention is should not be limited to a specific
number of transmitter modules 55 or receiver modules 51, 52.
[0041] The resistivity tool 40 may comprise one or more receiver
modules 61, 62 that are a greater distance from the transmitter
module 55 than the receiver modules 51, 52. A person having
ordinary skill in the art will appreciate that one or more of the
receiver modules 51, 52, 61, 62 may be incorporated into the
resistivity tool 40, and the present invention should not be
limited to requiring all of the receiver modules 51, 52, 61, 62.
The measurement between the transmitter module 55 and the receiver
modules 61, 62 may have a deeper depth of investigation into the
formation F. The signal level may be lower for the receiver modules
61, 62 than the receiver modules 51, 52. For example, the receiver
modules 61, 62 may measure weaker electromagnetic signals
encountered at relatively long distances from the transmitter
module 55, or at least distances great than those measured by the
receiver modules 51, 52.
[0042] The antennas on the receiver modules 61, 62 may be wound to
cause higher sensitivity. For example, the receiver modules 61, 62
may have a high sensitivity receiver antenna (hereinafter "HSR
antenna") comprising a coil with more winding turns than the
receiver antenna for the receiver modules 51, 52. In light of
receiver modules 61, 62 being farther away from the transmitter
module 55, the receivers 51, 52 may be referred to as the near
receivers.
[0043] One or more joints of wired drill pipe 20 may be positioned
between and connect the receiver modules 61, 62 and the BHA 10. As
shown in FIG. 3, the wired drill pipe 20 may have repeaters 100 for
amplifying telemetry signals transmitted by the wired drill pipe 20
as discussed in more detail hereafter. One or more of the
transmitter modules 55 and the receiver modules 51, 52, 61, 62 may
function as the repeaters 100 for the wired drill pipe 20 and/or
may be incorporated into the repeaters 100. For example, one of the
receiver modules 51, 52, 61, 62 may be positioned in the same drill
collar as one of the repeaters 100. The repeaters 100 of the wired
drill pipe 20 may be located at intervals between the drill bit 15
and Earth's surface. Thus, the receiver modules 51, 52, 61, 62 may
amplify the telemetry signals transmitted by the wired drill pipe
20 (the repeater function), and receive the electromagnetic signals
transmitted from the transmitter module 55 (the receiver function).
The receiver modules 51, 52, 61, 62 may have power available to
support the electronic circuitry for both functions. In an
embodiment, the transmitter module 55 may function as one of the
repeaters 100.
[0044] The transmitter antenna, the receiver antenna and/or the HSR
antennas may be wound along an axis of the resistivity tool 40 (z
axis) to create a dipole moment along the tool axis. The dipole
moment may be transverse to the axis of the resistivity tool 40,
such as, for example, at an x direction or a y direction, or,
alternatively, the dipole moment may be tilted relative to the axis
of the resistivity tool 40, such as, for example, at an x-z
direction or a y-z direction.
[0045] The resistivity tool 40 may be operated at or within a range
of predetermined frequencies, such as frequencies from
approximately one kHz to approximately two MHz. If the receiver
modules 61, 62 are distant from the BHA 10, the receiver modules
61, 62 may be operated at frequencies in the lower portion of the
predetermined ranges, such as in the lower range of about one kHz
to two MHz range or may even be operated at frequencies below 1
kHz. In an embodiment, the receiver modules 61, 62 distant from the
BHA 10 may be operated at frequencies approximately equal to one
kHz or less than one kHz. As the distance between the transmitter
module 55 and the receiver modules 51, 52, 61, 62 increase, a lower
frequency of operation may compensate for signal loss in the
formation F.
[0046] Referring again to FIG. 2, the wired drill pipe 20 may
provide synchronization and/or data transfer between the BHA 10 and
the receiver modules 51, 52, 61, 62. The transmitter module 55 and
the receiver modules 51, 52, 61, may be synchronized by sending a
trigger pulse, for example, from the transmitter module 55 to the
receiver modules 51, 52, 61, 62. The trigger pulse may be sent at a
time prior to sending the electromagnetic signal to prepare the
electronic circuitry of the receiver modules 51, 52, 61, 62 to
detect the electromagnetic signal. The time that the trigger pulse
may be sent may be adjusted based on time elapsed during generation
of the trigger pulse by the transmitter module 55, a time elapsed
during travel of the trigger pulse to the farthest away one of the
receiver modules 51, 52, 61, 62, and processing time of the
receiver modules 51, 52, 61, 62. The time elapsed during travel of
the trigger pulse to the receiver modules 51, 52, 61, 62 may depend
on the distance between the transmitter module 55 and the receiver
modules 51, 52, 61, 62.
[0047] The transmitter module 55 and the receiver modules 51, 52,
61, 62 may have internal clocks that may drift relative to each
other. For example, a time indicated by the clock of one of the
receiver modules 51, 52, 61, 62 at a specific time may not match a
time indicated by the clock of the transmitter module 55 at that
specific time. The drift may depend on time of use and temperature
encountered. The drift may cause association of inaccurate time
information with the data obtained by the receiver modules 51, 52,
61, 62. Messages transmitted between the transmitter module 55 and
the receiver modules 51, 52, 61, 62 using the wired drill pipe 20
may be used for synchronization of the clocks.
[0048] Synchronization may be periodic such that the transmitter
module 55 and the receiver modules 51, 52, 61, synchronize at
predetermined time intervals. A time interval for synchronization
may be based on the drift. For example, the time interval may be
one second if the drift is relatively high. As a further example,
the time interval may be one hour if the drift may be relatively
low.
[0049] The messages used for synchronization may be "ping"
messages. As known to one having ordinary skill in the art, a
"ping" message may be a message that requests a recipient device
for a response. Receipt of the response by the device that sent the
"ping" message may enable calculation of a round-trip transmission
time. A sending device of the transmitter module 55 and the
receiver modules 51, 52, 61, 62 may use the wired drill pipe 20 to
transmit the messages for synchronization to the other devices. The
messages may indicate a time provided by the clock of the sending
device and/or the round-trip transmission time. The transmitter
module 55 and the receiver modules 51, 52, 61, 62 may use the
messages to determine a rate of drift. The rate of drift may be
used to synchronize the clocks in the absence of the messages, such
as, for example, if communication using the wired drill pipe 20 is
interrupted.
[0050] A processor may be located in and/or in communication with
the transmitter module 55 and the receiver modules 51, 52, 61, 62.
The processor may receive the data from the transmitter module 55
and the receiver modules 51, 52, 61, for processing. The surface
terminal 5 may receive and/or process the data. The wired drill
pipe 20 may transmit the data between the transmitter module 55,
the receiver modules 51, 52, 61, 62 and/or the surface terminal
5.
[0051] FIG. 2 depicts a portion of the formation F having a first
layer 201, a second layer 202, a third layer 203, a fourth layer
204, a fifth layer 205, a sixth layer 206 and/or a seventh layer
207. The wellbore 30 may be drilled in the formation F through the
first layer 201, the second layer 202, the third layer 203 and the
fourth layer 204. The wellbore 30 may land in the fifth layer 205
and continue through the fifth layer 205 as a horizontal well.
[0052] The resistivity tool 40 may obtain measurements that may be
used to determine a formation model. The formation model may have
formation properties and/or boundary locations of adjacent layers.
The formation layer model may be used to make drilling decisions
such as geosteering, landing, etc. For example, the BHA 10 may
obtain measurements regarding the properties of the third layer
203, the fourth layer 204, the fifth layer 205, the sixth layer 206
and/or the seventh layer 207 (hereinafter "the properties of the
third layer through the seventh layer 203-207"), but the first
layer 201 and/or the second layer 202 may be beyond the depth of
investigation of the BHA 10. However, the BHA 10 may or may not be
able to obtain measurements regarding the properties of the first
layer 201 and/or the second layer 202 during horizontal drilling in
the fifth layer 205. The receiver module 61 may be positioned in or
adjacent to the fourth layer 204 at the time the drill string 14 is
depicted in FIG. 2. Assuming the properties of the first layer 201
and/or the second layer 202 do not change, the previously obtained
measurements regarding the properties of the first layer 201 and/or
the second layer 202 and the measurements regarding the properties
of the third layer through the seventh layer 203-207 may be used in
a forward model to calculate expected data for one or both of the
receiver module 61, 62.
[0053] An electromagnetic signal transmitted from the transmitter
module 55 and received by the receiver modules 61, 62 may be used
to compare with the forward model results. The processor and/or the
surface terminal 5 may compare the data based on the
electromagnetic signal with the expected data. Comparison of the
data based on the electromagnetic signal with the expected data may
indicate if the formation model may be accurate. For example,
comparison of the data based on the electromagnetic signal with the
expected data may indicate if the formation properties and/or the
boundary locations of adjacent layers of the formation model have
changed.
[0054] In the scenario depicted in FIG. 1, the measured and modeled
values are expected to agree within the noise level. The scenario
depicted in FIG. 2 is similar to the geometry of FIG. 1. However, a
region of interest 150 may be located in the second layer 202. The
region of interest 150 may be located at a distance from the
wellbore 30 that prevented detection when the BHA 10 was located in
the first layer 201, the second layer 202, the third layer 203
and/or the fourth layer 204. For example, the region of interest
150 may be a salt dome. The present invention is not limited to a
specific embodiment of the region of interest 150, and the region
of interest 150 may be any subsurface region.
[0055] The receiver modules 61, 62 may have sufficient depth of
investigation to detect the region of interest 150. The data based
on the electromagnetic signal received by the receiver modules 61,
62 may differ from the expected data. The difference between the
data based on the electromagnetic signal and the expected data may
indicate that the formation may have a feature not considered in
the formation model. The data based on the electromagnetic signal
may be used to determine properties of the region of interest 150,
such as, for example, a location or the shape and dimensions of the
region of interest 150.
[0056] Sensitivity of the electromagnetic signal to the region of
interest 150 may depend on the distance from the transmitter module
55 to the receiver modules 51, 52, 61, 62. The sensitivity of the
electromagnetic signal to the region of interest 150 is not a
single event. As drilling moves the BHA 10, the distance from the
transmitter module 55 to the receiver modules 51, 52, 61, 62 may
change. For example, comparing FIG. 2 with FIG. 4, in FIG. 4 the
receiver module 61 has moved into the horizontal section of the
well as a result of further drilling and the distance between the
transmitter module 55 and the receiver module 61 has increased
compared to the embodiment of FIG. 2. The embodiment of FIG. 4 may
have a larger depth of investigation. This increase in depth of
investigation favors the detection of region of interest 150. This
example demonstrates how the distance between the transmitter
antenna and the receiver antenna changes by the curvature in the
drill assembly and is typically at its maximum when the curvature
changes to a straight section. The data based on the
electromagnetic signal received by the receiver modules 61, 62 in
the scenario of FIG. 4 may be used to determine the properties of
the region of interest 150, such as, for example, the location of
the region of interest 150.
[0057] The resistivity tool 40 may be used for other applications
in drilling environment. For example FIG. 5 depicts a situation in
which a first well 301 has encountered the region of interest 150.
The region of interest 150 may be any subsurface region. A cylinder
305 located around the first well 301 may represent a radius of the
depth of investigation of the resisitivity tool 40 as described
previously. Typically, the cylinder 305 may cover a relatively
small portion of the region of interest 150 as the geological
features are usually large. The drill string 14 may be only capable
of measuring properties of the portion of the region of interest
150 that may be located within the cylinder 305. The properties of
the portion of the region of interest 150 that may be located
within the cylinder 305 may not provide detailed information about
the region of interest 150, such as, for example, a shape of the
region of interest 150, a size of the region of interest 150 and/or
the like.
[0058] A second well 302 that may be located adjacent to and/or
extend through the region of interest 150 may provide the detailed
information about the region of interest 150. As generally shown in
FIG. 5, the second well 302 may encircle the region of interest 150
and/or may enable determination of the detailed information about
the region of interest 150. The first well 301 and the second well
302 may not be located in the same plane. The present invention is
not limited to a specific embodiment or a specific location of the
first well 301 or the second well 302.
[0059] For example, the second well 302 may have a different
trajectory relative to the first well 301. FIG. 6 generally
illustrates that the second well 302 may be a side track well that
may originate from the first well 301. Alternatively, the second
well 302 may be drilled independently from the first well 301. The
second well 302 may be used for other purposes, such as, for
example, as a monitoring well, a secondary producer well, an
injection well and/or the like.
[0060] The second well 302 may be drilled to maintain a distance
from the region of interest 150. The distance of the second well
302 from the region of interest may be maintained by using the
resistivity tool 40 within the second well 302. Alternatively,
other well placement devices, such as, for example, sonic or fluid
typing tools may be used to maintain the distance of the second
well 302 from the region of interest 150 but it is desirable to
have as large a depth of investigation as possible and that is
provided by the ultra deep resisitivity tool 40.
[0061] The trajectory of the second well 302 may provide the
detailed information about the region of interest 150, such as, for
example, the shape of the region of interest 150, the size of the
region of interest 150 and/or the like. Measurements obtained by
tools within the second well 302 may provide properties of the
region of interest 150 from a location closer to the region of
interest 150 relative to the first well 301. The properties of the
region of interest 150 determined by the second well 302 may be
compared with properties of the region of interest 150 determined
by the first well 301 to assess possible variation of the
properties. For example, a water cone may be located adjacent to a
pre-existing well, and drilling a second well may provide
information regarding the water cone. As a further example, one or
more side track wells may be drilled to obtain other information,
and the resistivity tool 40 may be used in the side track wells to
increase the accuracy of the estimated position of the first well
301 and/or the second well 302 relative to the reference point 310
and/or each other. In addition, the resistivity tool 40 may be used
in the side track wells to obtain the detailed information
regarding the region of interest 150.
[0062] Another application of this invention is for measuring the
distance between two wells. As generally shown in FIG. 7, a
position of the first well 301 and/or a second well 302 relative to
a reference point 310 may be monitored. For example, the reference
point 310 may be located at the surface, such as, at a top of the
drill string 14 on the rig floor. The present invention is not
limited to a specific embodiment of the reference point 310. As
drilling proceeds, the position of the first well 301 and/or the
second well 302 relative to the reference point 310 may be
estimated using data obtained during the drilling. Inaccuracy in
the estimated position of the first well 301 and/or the second well
302 relative to the reference point 310 may increase as a depth of
the first well 301 and/or the second well 302 increases. For
example, the uncertainty in the position of the first well 301 is
represented by 301a and the uncertainty of the second well is
generally represented by 302a. A distance D is illustrated in FIG.
7 to show the actual distance between the first well 301 and the
second well 302. The distance D may be less than the uncertainty
302a of the second well 302 and/or less than the uncertainty 301a
of the first well 301.
[0063] The resistivity tool 40 may have a flexible architecture,
stemming from adjustable inter module spacing and programmable
frequency of operation. These features allow a user to optimize the
architecture for optimum signal level and/or depths of
investigation. Often, it is desired to drill a second well in the
vicinity of an existing cased well. In such a case, there may be
three desired objectives in such operation, namely a) to drill the
second well such that it intersects the existing well
(interception), b) to drill the second well such that it avoids the
existing well (collision avoidance), and c) drill the second well
such that it follows the existing well within some distance
(tracking). FIG. 8 shows a tracking scenario where a cased well 800
already exists and the second well 302 is being drilled at a
desired distance from the first. FIG. 9 shows a collision avoidance
scenario where the trajectory of the second well 302 is changed to
avoid collision with the cased well 800. Similarly, FIG. 10 shows
an interception scenario where the trajectory of the second well
302 is adjusted to ensure the two wells 302, 800 meet.
[0064] The presence of casings in the cased well 800 may be an
advantage for resistivity methods. This is due to the high
conductivity of the metallic casings and their high magnetic
permeability. The high conductivity of casing compared with the
background formation, causes strong conductivity contrast with the
background and aids in detecting the presence of the casing. In
addition, formation's lack of magnetic permeability coupled with
relatively large magnetic permeability of casing material creates
strong magnetic permeability contrast which is useful for
resistivity and magnetic ranging. The resistivity tool 40 utilizes
these advantages to achieve at least the three objectives
identified above.
[0065] Measurement of positions of the first well 301 and the
second well 302 relative to each other may increase accuracy of the
estimated position of the first well 301 and/or the estimated
position of the second well 302 relative to the reference point
310. Increasing the accuracy of the estimated position of the first
well 301 and/or the estimated position of the second well 302 may
increase accuracy of determination of a position of the region of
interest 150. The trajectory of the second well 302 may not be
pre-determined and/or may be adjusted during drilling based on the
measurements obtained during drilling. For example, the second well
302 may be moved to a different plane based on the information
regarding the region of interest 150.
[0066] During drilling of the second well 302, the measurements
obtained by tools having a shallower depth of investigation, such
as, for example, the receiver modules 50 located in the BHA 10, may
be used to steer the second well 302. The receiver modules 51, 52,
61, 62 located in the BHA 10 may enable determination of distances
between the second well 302 and the region of interest 150 more
accurately relative to tools having a larger depth of
investigation. The receiver modules 51, 52, 61, 62 may be used to
determine the positions of the first well 301 and the second well
302 relative to each other. For example, the receiver modules 51,
52, 61, 62 may enable determination of the positions of the first
well 301 and the second well 302 relative to each other after the
first well 301 has received casing. The receiver modules 51, 52,
61, 62 may determine a distance from a point located on the first
well 301 and a point located on the second well 302. Alternatively,
a magnetic ranging device may be used to determine the positions of
the first well 301 and the second well 302 relative to each other,
such as, for example, the magnetic ranging device disclosed in U.S.
Patent App. Pub. No. 2008/0041626 to Clarke, herein incorporated by
reference in its entirety.
[0067] Assume the z-axis to be along the axial tool direction. The
transmitter and receiver antennas may be tilted at 45 degree
relative to the tool axis however, the method of this invention is
not limited to tilted antennas transverse or axial or some
combination of these antennas can also be used. In addition, the
tilted antennas may have a tilt angle different from 45 degree. The
voltage measured by the receiver antennas is a function of the
coupling tensor the components of which can be extracted using the
methods well known in the art. Some of these components such as
(zz), and (xx)+(yy) are non-directional. However, the off diagonal
elements of the tensor are directional and can be used to determine
the azimuthal distribution of resistivity. The azimuthal
distribution of resistivity coupled with relatively deep depth of
investigation can be used to detect the presence of casing and
achieve tracking, avoidance or interception.
[0068] Assuming the casing is within the depth of investigation of
the resistivity tool 40, some components of the coupling tensor
will be highly affected by the presence of casing. For example, if
the resistivity tool 40 and the casing are roughly parallel (the
tracking case mentioned above) and are contained in the plane
defined by x and z coordinates, the couplings (xx), (yy), (xz), and
(zx) may be strongly affected. If the resistivity tool 40 is
aligned along z and the casing is aligned along y, then (zz), (zx),
(xz), and (xx) couplings may show strong response. Similarly if the
casing is along x instead of y, the components of interest will be
(zz), (zy), (yz), and (yy). Having mentioned the two extreme cases
of parallel and perpendicular orientations, most situations will
likely be between these two limits and thus all components of the
coupling tensor come into play. In these cases, it will be possible
to extract information about the casing in particular its relative
position and orientation.
[0069] FIG. 11a shows a magnetic dipole 700 as generated by one of
the coils in transmitter module 55. For FIG. 11A, the dipole 700 is
oriented normal to the plane. Excitation of the dipole 700 leads to
Eddy currents 702 circulating in the background formation. If the
dipole 700 is close to a metal casing 704, as shown in FIG. 11B,
the high conductivity of the casing 704 causes the Eddy currents
702 to change shape and flow through the casing 704. Comparing
FIGS. 11A and 11B, the shape change of the Eddy currents 702 can be
approximated by the presence of a reactive current loop 706 as
shown in FIG. 11B. The effect of casing 704 is then equivalent to
the magnetic field created by the reactive current loop 706, and
the signal measured by a receiver is the superposition of the
magnetic field from FIG. 11A and the field from the reactive
current loop 706 of FIG. 11B. To detect the casing 704 one needs to
separate the two magnetic fields and the use of relatively low
frequencies of operation (those below 10 kHz) may aid or improve
the process.
[0070] An inversion technique such as Bayesian or an iterative
minimization can be used to extract the casing information from the
received data or from the coupling tensor. The inversion will solve
for a set of parameters describing the formation (layer boundary
positions and orientations, resistivities of layer, etc) and a set
of parameters describing the casing (relative location, relative
orientation, magnetic permeability, cross-section, conductivity,
etc).
[0071] The wired drill pipe 20 located between the transmitter
module 55 and the receiver modules 51, 52, 61, 62 aids in the
measurement stage when the transmitter and receiver antennas need
to communicate data and timing information. In addition, the
high-speed telemetry provided by wired drill pipe 20 allows
measurements to be conducted at higher sampling rate and the large
volume of the data to be sent to surface. A processor located at
the surface, such as the surface terminal 5, uses the data and
delivers real-time geometrical information about relative position
between the existing well trajectory and nearby casing allowing
real time steering decisions to be made and implemented. The high
sampling rate is essential in determining the casing information
with high definition which may be needed to achieve casing
tracking, interception, or avoid collision. The success of this
method is due to a) high definition structural information about
the casing, b) the deep depth of investigation of the resistivity
tool 40 to provide maneuverings time, and c) availability of the
high data rate to allow real time trajectory adjustment decisions
and implementation of these decisions.
[0072] As generally shown in FIG. 3, the wired drill pipe 20 may
have the repeaters 100 that may facilitate obtaining measurements
at various points in the wellbore 30. Time-lapsed measurements may
be taken using repeated measurements from different sections of the
drill string 14. The drill string 14 may have a distance between
the repeaters 100, such as, for example, approximately fifteen
hundred feet. The distance between the repeaters 100 may be
adjusted to a desired distance. As each of the repeaters 100 passes
by a specific point in the wellbore, the repeaters 100 may obtain
measurements for a region adjacent to the specific point in the
wellbore. For example, if the repeaters 100 are spaced three
thousand feet apart and an average rate of penetration is ten feet
per minute, approximately one of the repeaters 100 may pass by a
specific point in the wellbore every five hours. Thus, the
repeaters 100 may provide a timed view of wellbore conditions, so
that conditions such as, for example, washout, invasion and/or the
like, may be observed as the conditions develop and/or corrective
actions may be taken. Corrective actions may be, for example,
moving the tool to a different position, changing drilling fluid
rates, changing drilling fluid characteristics, using a tool to
change pressure in various parts of the wellbore, circulating
specific chemicals to a controlled region and/or the like. The
present invention is not limited to a specific embodiment of the
conditions or the corrective actions.
[0073] As illustrated in FIG. 12, each of the repeaters 100 may
have a transmitter 110 and/or one or more receivers 120 at varying
distances from the transmitter 110. The varying distances of the
receivers 120 may enable different depths of investigation to be
used. As illustrated in FIG. 13, one or more additional receivers
121 may be located at a distance from the transmitter 110 that may
be greater than the distance between the receiver 120 and the
transmitter 110. For example, the additional receiver 121 may be
located ninety feet or more from the transmitter 110. The
additional receiver 121 may enable the electromagnetic signal
transmitted from the transmitter 110 to travel further into the
wellbore for a deeper depth of investigation.
[0074] Any number of additional receivers 110 may be employed, and
the additional receiver 121 may be located at any distance from the
transmitter 110. For example, the additional receivers 121 may be
located at twenty feet, thirty feet, sixty feet, ninety feet and
one hundred feet from the transmitter 110. The additional receiver
121 may be located adjacent to the repeaters 100. The additional
receiver 121 may be located adjacent to the BHA 10. Each of the
repeaters 100 may be housed in a section 21 of the wired drill pipe
20 that may have connectors 22 for attachment to adjacent sections
21 of the wired drill pipe 20. The additional receivers 121 may be
located in different sections 21 of the wired drill pipe 20
relative to the transmitter 110 that may transmit the
electromagnetic signal to the additional receiver 121.
[0075] The surface terminal 5 connected to the wired drill pipe 20
may display the information obtained by the BHA 10, the receiver
120 and/or the additional receiver 121. As discussed previously,
the surface terminal 5 may transmit control messages based on the
information. For example, the control messages may vary the depth
of investigation at various points of the drill string 14. The
surface terminal 5 may transmit the control messages at
predetermined time intervals. The surface terminal 5 may transmit
the control messages using the wired drill pipe 20. The control
messages may adjust the depth of investigation for each of the
transmitters 110, the receivers 120 and/or the additional receivers
121.
[0076] For example, the surface terminal 5 may direct the
additional receiver 121 that may be located a predetermined
distance from a specific one of the repeaters 100 to begin
recording data and/or may direct the transmitter 110 associated
with the specific repeater 100 that a predetermined depth of
investigation is desired. In response, the transmitter 110 may
adjust a frequency of the electromagnetic signal transmitted to
correspond to the predetermined depth of investigation. The
transmitter 110 may adjust other parameters to correspond to the
predetermined depth of investigation. Thus, the surface terminal 5
may control gathering of specific information at various locations
precisely when the specific information may be required.
[0077] As discussed previously, the repeaters 100 may amplify the
signals transmitted by the wired drill pipe 20. The repeaters 100
may be modules located between sections of the wired drill pipe 20
that may receive the signal, may amplify the signal and may
broadcast an amplified signal. The repeaters 100 may increase
transmission range of the signal. Each of the repeaters 100 may
have electronic circuitry and/or a power source. The power source
may, for example, be a battery, turbine or power harvesting
mechanism. Availability of power from the power source of the
repeaters 100 may enable association of sensors with the repeaters
100. Thus, the repeaters 100 may perform both repeater functions
and measurement functions. The sensors may be used for applications
other than telemetry amplification.
[0078] Alternatively, the sensors may be connected to the drill
string 14 by inserting the sensors between sections of the wired
drill pipe 20 similar to how the repeaters 100 are attached to the
wired drill pipe 20. The sensors may be designed to provide
repeater functions. Thus, the sensors may perform both repeater
functions and measurement functions. Whether the repeaters 100 are
designed to have measurement functions or the sensors are designed
to have repeater functions, dual purpose modules may distribute the
sensors along the length of the drill string 14.
[0079] The sensors distributed along the length of the drill string
14 may travel downward at a rate equal to or greater than the rate
of penetration as the drilling occurs. Alternatively, during
removal of the drill string 14 from the wellbore, the sensors
distributed along the length of the drill string 14 may travel
upward at a rate. Thus, the position of the sensors may be time
dependent. The distribution of the sensors may depend on the nature
of the physical phenomenon being interrogated by the sensor, the
rate of travel and/or a required repeater distance. A constant
average rate of penetration may be assumed.
[0080] FIG. 14 compares responses for sensors having measurements
that depend on an independent variable linearly, exponentially,
inversely, or as a square root. For example, the independent
variable may be time or depth. The present invention is not limited
to a specific independent variable. For the sensors having
measurements that depend on the independent variable linearly, the
equation y=ax+b may be used. The sensors may be located at
intervals .DELTA.x such that the measured quantity y may be
regularly spaced. .DELTA.y may be approximately constant. Taking
the derivative and solving for .DELTA.x leads to
.DELTA.x=.DELTA.y/a. Since .DELTA.y may be approximately constant,
.DELTA.x may be approximately constant, and the sensors may be
distributed uniformly along the drill string 14.
[0081] For the sensors having measurements that depend on the
independent variable exponentially, the equation y=a exp(.+-.bx)
may be used. Taking the derivative and solving for .DELTA.x leads
to .DELTA.x=.+-.(.DELTA.y/ab)exp(.+-.bx). Thus, for the sensors
having measurements with an exponential growth (positive exponent)
dependence, the distance between adjacent sensors may decrease
exponentially. For the sensors having measurements following an
exponential decay (negative exponent) dependence, the distance
between adjacent sensors may increase exponentially.
[0082] Similarly, for the sensors having measurements that depend
on the independent variable inversely, the equations y=a/(bx)
and/or .DELTA.x=-(b.DELTA.y/a)x.sup.2 may be used. Thus, the
sensors having measurements that depend on the independent variable
inversely may be distributed such that the distance between
adjacent sensors may increase as x.sup.2. For the sensors having
measurements that depend on the independent variable as a square
root, y=a sqrt(bx) and .DELTA.x=(2.DELTA.y/a sqrt(b))sqrt(x). Thus,
the sensors having measurements that depend on the independent
variable as a square root may be distributed as sqrt(x) which
varies with x, but the distance variation in successive pairs of
the sensors may become smaller as x increases. The present
invention is not limited to the dependences discussed above, and
any dependence on x may be analyzed by taking the derivative and
solving for variation in x.
[0083] FIG. 15 shows a graph of .DELTA.x versus x for the
dependences discussed above. The sensors having measurements that
depend on the independent variable linearly may have a constant
distance between the adjacent sensors. The sensors having
measurements that depend on the independent variable inversely and
the sensors having measurements that depend on the independent
variable as a square root may require more closely spaced sensors
at the outset and increasingly less of the sensors at later times.
The sensors having measurements that depend on the independent
variable exponentially require less sensors at the outset and
increasingly more closely spaced sensors at later times.
[0084] The measurements of the sensors may be characterized in one
of the following two categories: measuring a property at the same
depth at various times, or measuring a property at various depths.
If the property is measured at the same depth at various times,
successive sensors may provide measurements whenever each of the
sensors reach the depth. The measurements may be acquired at time
intervals that may be based on the rate of penetration and the
distance between the sensors. If the property is measured at
various depths and is expected to be time independent, then the
distributed sensors may provide a continuous log of the property as
the drilling proceeds. For both measurement categories, the
measurements acquired during drilling may be supplemented by
measurements acquired during removal of the drill string 14 from
the wellbore.
[0085] If the property is measured at the same depth at various
times, the sensors may be distributed along the drill string 14. As
the drill string 14 travels in a downward direction, different
sensors measure the same property at various times. Thus, depending
on the type of dependence of the measurement, the distance between
the sensors .DELTA.x may be adjusted to achieve the desired
measurements.
[0086] Distribution of fluids within an invaded zone is an example
of how the property changes as a function of time. The distribution
of fluids may be related to the volume of filtrate. The volume of
the filtrate may follow a square root of time dependence.
Initially, the volume of filtrate may be large, but as time passes,
an increasingly thicker mud cake may be formed that may limit an
amount of filtrate entering the formation. Referring to FIGS. 16
and 17, the sensors for determining the volume of filtrate may be
spaced closer together at short times and may be spaced farther
apart at longer times. Such spacing of the sensors may be
consistent with more available area for sensor placement in a
section of the drill string 14 close to the drill bit 15 relative
to sections of the drill string 14 farther away from the drill bit
15.
[0087] FIG. 16 shows a possible sensor distribution for measurement
of the volume of filtrate. A first sensor 401 and/or a second
sensor 402 may be located on or adjacent to the BHA 10. A third
sensor 403, a fourth sensor 404 and/or a fifth sensor 405 may be
connected to the wired drill pipe 20. The distances between the
sensors 401-405 may be any predetermined distances appreciated by a
person having ordinary skill in the art. The distances between the
sensors 401-405 may be similar, the same, or different. For
example, the first sensor 401 may be a first distance D1 from the
second sensor 402, and the second sensor 402 may be a second
distance D2 from the third sensor 403 which may be greater than the
first distance D1. The fourth sensor 404 may be a third distance D3
from the third sensor 403 which may be greater than the first
distance D1 and the second distance D2. The fifth sensor 405 may be
a fourth distance D4 from the fourth sensor 404 which may be
greater than the first, second and third distances D1-D3. FIG. 16
illustrates an embodiment of spacing the sensors 401-405 with
arbitrary units, but the invention should not be deemed as limited
to these distances as previously mentioned. The second sensor 402
may be one unit from the first sensor 401, the third sensor 403 may
be 1.42 units from the second sensor 402, the fourth sensor 404 may
be 1.72 units from the third sensor 403 and/or the fifth sensor 405
may be two units from the fourth sensor 404. The present invention
is not limited to specific distances between the first sensor 401,
the second sensor 402, the third sensor 403, the fourth sensor 404
and/or the fifth sensor 405 (hereinafter "the sensors
401-405").
[0088] The third sensor 403, the fourth sensor 404 and/or the fifth
sensor 405 may be the dual purpose modules that may perform both
measurement functions and repeater functions. The sensors 401-405
may be a resistivity sensor and/or a sensor capable of measuring a
thickness of the mud cake, for example. The sensors 401-405 may be
a different type of sensor capable of measuring a thickness of the
mud cake may also require the same axial distribution. For example,
the sensor capable of measuring the thickness of the mud cake may
be an ultrasonic sensor that measures the thickness using
ultrasonic wave reflections from the formation and an interface of
the mud and the mud cake. The present invention is not limited to a
specific embodiment of the sensors 401-405.
[0089] The depth of investigation of the sensors 401-405 may be
adjusted. For example, the first sensor 401 and/or the second
sensor 402 may be resistivity sensors and/or may have relatively
shallow depths of investigation. The third sensor 403, the fourth
sensor 404 and/or the fifth sensor 405 may be resistivity sensors
and/or may have increasingly larger depths of investigation. As a
further example, the first sensor 401 and/or the second sensor 402
may be ultrasonic sensors and/or may have very fine resolution to
handle very thin mud cakes. The third sensor 403, the fourth sensor
404 and/or the fifth sensor 405 may be ultrasonic sensors and/or
may have less resolution to handle thick mud cakes.
[0090] Assuming a piston-like invasion, an invasion front may
follow fourth root of time dependence. The filtrate may push the
invasion front away from the wellbore to cause a cylindrical
invasion. A cross section of the cylinder may be a circle with the
invasion front being the radius of the circle. The filtrate volume
may be proportional to the area of the circle. Since filtrate
volume may vary with the square root of time, .pi.r.sup.2 .alpha.
sqrt (t) or r .alpha. .sup.4sqrt(t). The sensors may be positioned
at appropriate locations to monitor the invasion front. Some of the
sensors may be located on the BHA 10. Other sensors may be located
on the dual purpose modules connected to the wired drill pipe
20.
[0091] Some properties of the mud column and the formation are
depth dependent but change minimally as a function of time. For
example, the formation temperature increases linearly with depth,
and the drilling process may not change the formation temperature
significantly. If mud density and gravitational acceleration do not
change, pressure of the mud column is a function of depth and
changes minimally as a function of time. If the property is
measured at various depths and is expected to be time independent,
the distributed sensors may provide a continuous log of the
property as the drilling proceeds. For measurements of the property
at various depths, the distance between the sensors may be a
function of how the property varies with depth. Thus, sensor
spacing for measurements of a time independent property at various
depths may be similar to measurements of a property at the same
depth at various times.
[0092] Distributed pressure sensors that may measure hydrostatic
mud column pressure in the wellbore may follow the relationship
P=.rho.gh where P is the pressure, .rho. is average mud density, g
is gravitational acceleration and h is the height of the mud
column. Since P varies linearly with h (assuming g remains
constant), the optimum distribution for the sensors may be
equidistant, as generally shown in FIG. 17. Each of the repeaters
100 may be equipped with a pressure sensor, and the dual purpose
modules may be distributed at equal distances along the drill
string 14. The distance may be based on a desired pressure
resolution and/or the rate of penetration, for example.
[0093] Similarly, when measurement of temperature as a function of
depth is required, temperature sensors may be coupled with the
repeaters 100 in the dual purpose modules. Since the temperature
may vary linearly with depth, the dual purpose modules may be
distributed at equal distances along the drill string 14, as
generally shown in FIG. 17 where the distances D1-D4 are displayed
as approximately equal. The distance may be based on a desired
temperature resolution and/or the rate of penetration, for
example.
[0094] If the sensor intervals are the same as the distance
required for the repeaters 100, the dual purpose modules may be
employed throughout. If the sensor intervals are longer than the
distance required for the repeaters 100, some of the dual purpose
modules may be replaced with modules having either no sensing
capability or having sensors of a different nature. Alternatively,
dual purpose modules may be employed throughout with the sensor
measurement at distances less than the interval treated as
additional information or not used. The wired drill pipe 20 may
support communication of the measurements from the additional
sensors.
[0095] If the sensor intervals are shorter than the distance
required for the repeaters 100, some of the dual purpose modules
may be replaced with modules that do not perform repeater
functions. Alternatively, dual purpose modules may be employed
throughout. Additional repeaters 100 may enhance the quality of the
signal transmitted by the wired drill pipe 20.
[0096] FIG. 18 generally illustrates the resistivity tool 40 in an
embodiment of the present invention. The electromagnetic signal may
be transmitted into the formation from the transmitter module 55
and/or may be received by one or more of the receiver modules 51,
52, 61, 62. The electromagnetic signals received by the receiver
modules 51, 52, 61, 62 may be processed using two different
approaches, namely a relative approach and an absolute approach. In
the absolute approach, each of the receiver modules 50 may be
treated independently. For example, the absolute approach may be a
measure of the signal strength at the transmitter module 55 minus
the signal strength at one of the receiver modules 51, 52, 61, 62
(T-Rx). An amplitude and/or phase data may be used to determine
formation properties that have influenced the electromagnetic
signal. In the absolute approach, the electromagnetic signal may
have a depth of investigation that may be approximately
proportional to the distance between the transmitter antenna of the
transmitter module 55 and the receiver antenna of the receiver
module 50. At low frequencies of the electromagnetic signal, a
resolution of the electromagnetic signal may be approximately
proportional to the distance between the transmitter antenna of the
transmitter module 55 and the receiver antenna of one of the
receiver modules 51, 52, 61, 62. A gain of the transmitter antenna
of the transmitter module and/or the receiver antenna of the
receiver module 50 may be measured before transmittal of the
electromagnetic signal.
[0097] In the relative approach, the measurements from at least two
of the receiver modules 50 may be combined to determine a relative
signal. The relative signal may be the ratio of the voltages or, if
the electromagnetic signals are expressed in decibels, the
difference between the strength of the signals. For example, the
relative approach may be the difference in signal strength between
the transmitter module 55 and the receiver module 51 divided by the
difference in signal strength between the transmitter module 55 and
the receiver module 52. Of course, this approach may be applied for
any of the receiver modules 51, 52, 61, 62. The relative signal may
have a depth of investigation that may be proportional to the
distance between the receiver antennas of the receiver modules 50.
The distance between the receiver antennas of the receiver module
51 may be less than the distance from one of the receiver antennas
of the receiver modules 52, 61, 62 to the transmitter antenna of
the transmitter module 55. The relative signal may have a smaller
depth of investigation relative to the electromagnetic signal.
Resolution of the relative signal may be a function of the distance
between the receiver antennas and/or may be higher than the
resolution of the electromagnetic signal of the absolute approach.
The resolution of the relative signal may be adjusted to a desired
value in designing the propagation electromagnetic logging
tool.
[0098] For the relative signal, the gain of the transmitter antenna
may be canceled by taking the ratio of the electromagnetic signals
received by the receiver antennas. Thus, the gain of the receiver
antennas may be determined and/or the gain of the transmitter
antenna may not be determined for the relative approach.
[0099] The high resolution provided by the relative signal of the
receiver antennas of the receiver modules 51, 52, 61, 62 may be
implemented for measurements acquired proximate to the wellbore 30.
For example, as shown in FIG. 19, the resistivity tool 40 may have
the transmitter module 55 located adjacent to the drill bit 15. The
resistivity tool 40 may have the first receiver module 51 and/or
the second receiver module 52 distributed within the BHA 10. The
resistivity tool 40 may use the absolute approach by treating the
first receiver module 51 and the second receiver module 52
independently and/or using the amplitude and/or the phase data to
determine the formation properties that have influenced the
electromagnetic signal. The resistivity tool 40 may use the
absolute approach to determine the formation properties at
relatively large radial distances from a wall of the wellbore
30.
[0100] As shown in FIG. 20, the receiver module 51 may have a first
receiver antenna 151 and a second receiver antenna 152. In FIG. 20,
the dipole moments of the first antenna 151 and/or the second
antenna 152 of the receiver module 51 are shown. In the embodiment
depicted in FIG. 20, the first receiver antenna 151 and/or the
second receiver antenna 152 of the receiver module 51 may be tilted
at an angle with respect to the axis of the first receiver module
51, such as approximately forty-five degrees. The electromagnetic
signals received by the first receiver antenna 151 and/or the
second receiver antenna 152 of the receiver module 51 may be
processed in combination using the relative approach to provide
high resolution information about the formation. A desired
resolution may be selected, and the receiver antenna 151 may be
connected to the receiver module 51 at a distance from the second
receiver antenna 152 of the first receiver module 51 such that the
distance provides the selected resolution. Thus, electromagnetic
signals from the transmitter module 55 may be processed using both
the absolute approach and the relative approach. Of course in
embodiments, the above-description could apply to any one of the
receiver modules 51, 52, 61, 62.
[0101] The dual purpose modules of the receiver modules 51, 52, 61,
62 may have the repeater function in addition the first receiver
antenna 151 and/or the second receiver antenna 152. The dual
purpose module may have threads 160 on a female portion 161 and/or
a male portion 162 for connecting to sections of the wired drill
pipe 20.
[0102] As shown in FIG. 21, the resistivity tool 40 may have the
receiver modules 61, 62 located at distances from the transmitter
module 55, such as distances longer than one hundred feet. The
distances of the receiver modules 61, 62 from the transmitter
module 55 may provide a deeper depth of investigation relative to
the receiver modules 51, 52. However, the signal level may be lower
relative to the receiver modules 51, 52 due to the distances of the
receiver modules 61, 62 are from the transmitter module 55. The
receiver modules 61, 62 may use the HSR antennas and/or a lower
frequency of operation to enhance the signal level. A higher power
level of transmission may be used to enhance the received signal
level. The receiver modules 61, 62 may be combined with the
repeaters 100 to provide the dual purpose modules that may perform
both the measurement functions and the repeater functions.
[0103] The dual purpose modules of the receiver modules 61, 62 may
be equipped with at least two of the HSR antennas for processing of
the electromagnetic signals using the absolute approach and/or the
relative approach. As discussed previously, the relative signal may
have higher resolution and a shallower depth of investigation
relative to the electromagnetic signal processed using the absolute
approach. The electromagnetic signals may be processed using the
absolute approach for deeper depth of investigation relative to the
relative approach. The distance between the dual purpose modules of
the receiver modules 61, 62 may be designed to achieve the desired
depth of investigation and the desired resolution.
[0104] The transmitter antennas and the receiver antennas may be
coils wound to generate a magnetic dipole. The coils may wind along
the axis of the module and/or the wellbore to generate a dipole
moment in the same direction and/or to form a z axis coil.
Alternatively, the coils may be tilted or transverse relative to
the axis of the module and/or the wellbore 30. A tool may have any
combination of antenna orientations. For example, the transmitter
module 55 and/or the receiver modules 51, 52, 61, 62 may have any
combination of antenna orientations. The receiver modules 51, 52,
61, 62 may have two antennas having the same orientation, such as,
for example, both tilted or both transverse. The electromagnetic
signals from antennas having the same orientation may be easier to
combine and interpret relative to signals from antennas having
different orientations.
[0105] Antennas having different orientations may provide
advantages. For example, as shown in FIG. 22, the first antenna 151
of the receiver module 51 may be tilted at a first angle, such as
forty-five degrees, relative to the axis of the first receiver
module 51. Thus, the first receiver antenna 151 of the first
receiver module 51 may act as a combination of an x-directed
receiver and a z-directed receiver. The second receiver antenna 152
of the receiver module 51 may be tilted at a second angle, such as
135 degrees, relative to the axis of the first receiver module 51.
Thus, the second receiver antenna 152 of the receiver module 51 may
act as a combination of an x-directed receiver and a z-directed
receiver. The arrangement depicted in FIG. 22 may enable the sum
and the difference of signals from the first receiver antenna 151
and the second receiver antenna 152 of the receiver module 51 to
provide pure x-directed receivers and pure z-directed receivers
with information different than that acquired by the pure
x-directed receivers and the pure z-directed receivers.
[0106] In summary, the resistivity tool 40 may have the transmitter
module 55 and the receiver modules 51, 52 that may be located
adjacent to the drill bit 15, and the receiver modules 61, 62
located at greater distances from the drill bit 15 relative to the
receiver modules 51, 52. The receiver modules 51, 52, 61, 62 may
also perform repeater functions for the wired drill pipe 20. The
resistivity tool 40 may provide information regarding the region of
interest 150. The resistivity tool 40 may be used in two or more
wells to improve accuracy of determination of position of the wells
relative to each other and/or a reference point. In some
implementations additional measurements other than resistivity may
be made where sensors that obtain a measurement may be spaced from
each other based on the dependence of the measurement on an
independent variable.
[0107] It should be understood that various changes and
modifications to the presently preferred embodiments described
herein will be apparent to those having ordinary skill in the art.
Such changes and modifications may be made without departing from
the spirit and scope of the present invention and without
diminishing its attendant advantages. It is, therefore, intended
that such changes and modifications be covered by the appended
claims.
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