Note: Descriptions are shown in the official language in which they were submitted.
CA 02634650 2008-05-30
PERMANENT DOWNHOLE DEPLOYMENT OF OPTICAL SENSORS
BACKGROUND OF THE INVENTION
Field of the Invention
The present invention generally relates to methods and apparatus for use in
oil
and gas wellbores. More particularly, the invention relates to using
instrumentation to
monitor downhole conditions within wellbores.
Description of the Related Art
In well completion operations, a wellbore is formed to access hydrocarbon-
bearing formations by the use of drilling. Drilling is accomplished by
utilizing a drill bit
that is mounted on the end of a drill support member, commonly known as a
drill string.
To drill within the wellbore to a predetermined depth, the drill string is
often rotated by a
top drive or rotary table on a surface platform or rig, or by a downhole motor
mounted
towards the lower end of the drill string. After drilling to a predetermined
depth, the drill
string and drill bit are removed and a section of casing is lowered into the
wellbore. An
annular area is thus formed between the string of casing and the formation.
The casing
string is temporarily hung from the surface of the well. A cementing operation
may
optionally be conducted in order to fill the annular area with cement and set
the casing
string within the wellbore. Using apparatus known in the art, the casing
string may be
cemented into the wellbore by circulating cement into the annular area defined
between
the outer wall of the casing and the borehole. The amount and extent of cement
in the
annular area may vary from a small amount of cement only at the lower portion
of the
annulus to a large amount of cement extending to the surface or the top of the
casing
string. The combination of cement and casing strengthens the wellbore and
facilitates
the isolation of certain areas of the formation behind the casing for the
production of
hydrocarbons.
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It is common to employ more than one string of casing in a wellbore. In this
respect, the well is drilled to a first designated depth with a drill bit on a
drill string. The
drill string is removed. A first string of casing or conductor pipe is then
run into the
wellbore and set in the drilled out portion of the wellbore, and cement may be
circulated
into the annulus behind the casing string. Next, the well is drilled to a
second
designated depth, and a second string of casing, or liner, is run into the
drilled out
portion of the wellbore. The second string is set at a depth such that the
upper portion
of the second string of casing overlaps the lower portion of the first string
of casing.
The second liner string is then fixed, or "hung" off of the existing casing by
the use of
slips which utilize slip members and cones to wedgingly fix the new string of
liner in the
wellbore. The second casing string may then be cemented. This process is
typically
repeated with additional casing strings until the well has been drilled to
total depth. As
more casing strings are set in the wellbore, the casing strings become
progressively
smaller in diameter in order to fit within the previous casing string. In this
manner, wells
are typically formed with two or more strings of casing of an ever-decreasing
diameter.
As an alternative to the conventional method, drilling with casing is a method
increasingly used to place casing strings of decreasing diameter within the
wellbore.
This method involves attaching a cutting structure in the form of a drill bit
to the same
string of casing which will line the wellbore. Rather than running a drill bit
on a smaller
diameter drill string, the drill bit or drill shoe is run in at the end of the
larger diameter of
casing that will remain in the wellbore and may be cemented therein. Drilling
with
casing is often the preferred method of well completion because only one run-
in of the
working string into the wellbore is necessary to form and line the wellbore.
While drilling the drill string or the casing string into the formation,
drilling fluid is
ordinarily circulated through the inner diameter of the casing string or drill
string, out
through the casing string or drill string, and up around the outer diameter of
the casing
string or drill string. Typically, passages are formed through the drill bit
to allow
circulation of the drill fluid. Fluid circulation prevents collapse of the
formation around
the drill string or casing string, forces the cuttings produced by the drill
bit drilling
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through the formation out from the wellbore and up to the surface rather than
allowing
the cuttings to enter the inner diameter of the drill string or casing string,
and facilitates
the drilling process by forming a path through the formation for the drill
bit.
Recent developments have allowed sensing of parameters within the wellbore
and within the formation during the life of a producing well. Typically, the
drill string or
casing string with the drill bit attached thereto is drilled into the
formation to a depth.
When drilling with the drill string, the drill string is removed, a casing
string is placed
within the drilled-out wellbore, and the casing string may be cemented into
the wellbore.
When drilling with casing, the casing string may be cemented into place once
it has
drilled to the desired depth within the formation. Production tubing is then
inserted into
the casing string, and perforations are placed through the production tubing,
casing
string, cement around the casing string, and the formation at the desired
depth for
production of hydrocarbons. The production tubing may have sensors therearound
for
sensing wellbore and formation parameters while drilling and during production
operations.
Historically, monitoring systems have used electronic components to provide
pressure, temperature, flow rate and water fraction on a real-time basis.
These
monitoring systems employ temperature gauges, pressure gauges, acoustic
sensors,
seismic sensors, electromagnetic sensors, and other instruments or "sondes",
including
those which provide nuclear measurements, disposed within the wellbore. Such
instruments are either battery operated, or are powered by electrical cables
deployed
from the surface. The monitoring systems have historically been configured to
provide
an electrical line that allows the measuring instruments, or sensors, to send
measurements to the surface.
Recently, optical sensors have been developed which communicate readings
from the wellbore to optical signal processing equipment located at the
surface. Optical
sensors may be disposed along the production tubing within a wellbore. An
optical line
or cable is run from the surface to the optical sensor downhole. The optical
sensor may
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be a pressure gauge, temperature gauge, acoustic sensor, seismic sensor, or
other
sonde. The optical line transmits optical signals to the optical signal
processor at the
surface.
The optical signal processing equipment includes an excitation light source.
Excitation light may be provided by a broadband light source, such as a light
emitting
diode (LED) located within the optical signal processing equipment. The
optical signal
processing equipment also includes appropriate equipment for delivery of
signal light to
the sensor(s), e.g., Bragg gratings or lasers and couplers which split the
signal light into
more than one leg for delivery to more than one sensor. Additionally, the
optical signal
processing equipment includes appropriate optical signal analysis equipment
for
analyzing the return signals from the Bragg gratings.
The optical line is typically designed so as to deliver pulses or continuous
signals
of optic energy from the light source to the optical sensor(s). The optical
cable is also
often designed to withstand the high temperatures and pressures prevailing
within a
hydrocarbon welibore. Preferably, the optical cable includes an internal
optical fiber
which is protected from mechanical and environmental damage by a surrounding
capillary tube. The capillary tube is made of a high strength, rigid-walled,
corrosion-
resistant material, such as stainless steel. The tube is attached to the
sensor by
appropriate means, such as threads, a weld, or other suitable method. The
optical fiber
contains a light guiding core which guides light along the fiber. The core
preferably
employs one or more Bragg gratings to act as a resonant cavity and to also
interact
with the sonde.
While optical sensors placed on production tubing allow measurements while the
production tubing is located within the wellbore, the sensors on production
tubing do not
allow monitoring of wellbore and formation conditions during the drilling and
well
completion operations and after the production tubing is removed from the
wellbore.
Thus, the sensors are only deployed temporarily while the production tubing is
within
the wellbore. Furthermore, when employing seismic sensors which need to be
coupled
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to the formation, sensors located on production tubing are located at a
distance from
the formation, so that measurements of formation parameters derive some
inaccuracy
due to signal attenuation of the sensor without coupling the sensor to the
formation.
Coupling the sensors to the formation requires complicated maneuvers and
equipment
across the distance between the production tubing and the formation.
Accordingly, there is a need for apparatus and methods for permanently
deploying measurement devices. There is a need for apparatus and methods for
measuring wellbore and formation conditions throughout drilling and well
completion
operations, well production operations, and the remaining operations of a
well.
Furthermore, there is a need for apparatus and methods for locating
measurement
devices closer to the formation than is currently possible to increase the
accuracy of the
measured parameters and to facilitate coupling of the optical sensors to the
formation.
SUMMARY OF THE INVENTION
In one aspect, the present invention involves an apparatus for permanently
measuring wellbore or formation parameters, comprising a casing string
permanently
located within a wellbore, and at least one optical sensor attached to the
casing string,
the at least one optical sensor capable of measuring one or more wellbore or
formation
parameters. In another aspect, the present invention provides an apparatus for
permanently measuring wellbore or formation parameters, comprising a casing
string
permanently located within a wellbore, and at least one optical sensor located
at least
partially within a wall of the casing string, the at least one optical sensor
capable of
measuring one or more wellbore or formation parameters.
In yet another aspect, the present invention provides a method of permanently
monitoring wellbore or formation parameters, comprising providing a casing
string
having at least one optical sensor attached thereto, locating the casing
string within a
wellbore, and measuring one or more wellbore or formation parameters with the
at least
one optical sensor.
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In another aspect, the present invention includes an apparatus for measuring
fluid flow through a casing string, comprising a casing string permanently
located within
a wellbore, one or more optical sensors attached to the casing string for
measuring
parameters of a fluid flowing through the casing string, and control circuitry
and signal
processing adapted to determine a composition of the fluid or flow rate of the
fluid
based on one or more signals received from the one or more optical sensors. In
yet
another aspect, the present invention includes a method for determining a flow
rate or
one or more volumetric fractions of individual phases of a fluid flowing
through a casing
string, comprising locating a casing string having one or more optical sensors
attached
thereto within a wellbore, measuring one or more parameters of the fluid
flowing
through the casing string with the one or more optical sensors, and using the
one or
more parameters to determine the flow rate of the fluid or one or more
volumetric
fractions of the fluid.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the present
invention
can be understood in detail, a more particular description of the invention,
briefly
summarized above, may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however, that the
appended
drawings illustrate only typical embodiments of this invention and are
therefore not to
be considered limiting of its scope, for the invention may admit to other
equally effective
embodiments.
Figure 1 is a cross-sectional view of a casing string within a wellbore. An
optical
sensor is permanently deployed on an outer surface of the casing string
through
attachment of a sensor protector to the outer surface of the casing string,
the optical
sensor being housed within the sensor protector.
Figure 2 is a cross-sectional view of a casing string within a wellbore. An
optical
sensor is housed within a protective pocket on a mandrel. The mandrel is
located in
the casing string.
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Figure 3 is a cross-sectional view of a casing string within a wellbore. An
optical
sensor is embedded within a wall of the casing string.
Figure 4 is a cross-sectional view of a casing string within a wellbore. An
optical
sensor is permanently deployed with the casing string through the attachment
of a
sensor protector to an inner surface of the casing string, the optical sensor
housed
within the sensor protector.
Figure 5 is a cross-sectional view of a casing string within a wellbore. An
optical
sensor is attached directly to the outer surface of the casing string.
Figure 6 is a cross-sectional view of a flow meter disposed in a casing
string, the
casing string located within a wellbore. The flow meter is permanently
deployed within
the wellbore on the casing string.
Figure 7 is a cross-sectional view of a flow meter disposed within a casing
string,
the casing string having an earth removal member operatively attached to its
lower end.
The casing string is shown drilling into the formation.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
In contrast to the current practice of deploying sensors during production
operations with production tubing, the present invention provides apparatus
and
methods for permanently deploying optical sensors for use in measuring
wellbore
parameters during all wellbore operations, including but not limited to
completion
operations, drilling operations, and intervention operations. The present
invention also
beneficially provides methods and apparatus for placing optical sensors within
the
wellbore earlier in the wellbore operations, specifically during drilling and
completion of
the well, which occur prior to production operations. Additionally, the
present invention
includes apparatus and methods for locating seismic sensors closer to the
formation
than is possible with the current use of production tubing for the deployment
of optical
sensors, by use of one or more optical sensors deployed with a casing string.
Although
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pressure and temperature sensing does not require coupling of the optical
sensor to the
formation, a seismic sensor (e.g. an accelerometer or geophone) must be
coupled to
the formation by either cementing the seismic sensor into place or by placing
the
sensor into significant contact with the formation. The present invention
facilitates
coupling of seismic optical sensors to the formation, thereby increasing
accuracy of the
seismic readings.
As used herein, an "optical sensor" may comprise any suitable type of optical
sensing elements, such as those described in U.S. Patent Number 6,422,084,
entitled
"Bragg Grating Pressure Sensor". For example, the optical sensor may comprise
an
optical fiber, having the reflective element embedded therein; and a tube,
having the
optical fiber and the reflective element encased therein along a longitudinal
axis of the
tube, the tube being fused to at least a portion of the fiber. Alternatively,
the optical
sensor may comprise a large diameter optical waveguide having an outer
cladding and
an inner core disposed therein.
Optical Sensor Deployment
Figures 1-7 show the various ways in which one or more optical sensors may be
permanently deployed on casing. One or more optical sensors may be deployed on
the
outside of the casing, as shown in Figures 1-2 and 5, or deployed on the
inside of the
casing, as shown in Figure 4. Alternatively, one or more optical sensors may
be
embedded within the casing, as shown in Figure 3. One or more optical sensors
may
also be part of a flow meter disposed in a casing string, as shown in Figures
6-7.
Exemplary Deployment Apparatus and Techniques
Figure 1 shows an embodiment of the present invention. A casing string 5 is
shown within a wellbore 10 formed within a formation 15. The casing string 5,
which
comprises one or more casing sections threadedly connected to one another, has
an
inner surface 6 and an outer surface 7. A physically alterable bonding
material 20,
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preferably cement, may be utilized to permanently set the casing string 5
within the
wellbore 10.
A sensor carrier 25 is attached to the outer surface 7 of the casing string 5
and
disposed circumferentially around the casing string 5. Within the sensor
carrier 25 is an
optical sensor 30, which is used to sense conditions such as temperature,
pressure,
acoustics, and/or seismic conditions, within the wellbore 10 and the formation
15. The
sensor carrier 25 attaches the optical sensor 30 to the outer surface 7 of the
casing
string 5, as well as protects the optical sensor 30 from the often harsh
environment
within the wellbore 10.
Optical sensors offer one alternative to conventional electronic sensors.
Typically, optical sensors have no downhole electronics or moving parts and,
therefore,
may be exposed to harsh downhole operating conditions without the typical loss
of
performance exhibited by electronic sensors. The optical sensor 30 may utilize
strain-
sensitive Bragg gratings (not shown) formed in a core of one or more optical
fibers (not
shown) included in an optical cable 55. The optical cable 55 is connected at
one end to
the optical sensor 30 and runs through the sensor carrier 25, alongside the
outer
surface 7 of the casing string 5, and to a surface 65 of the wellbore 10.
Bragg grating-
based sensors are suitable for use in very hostile and remote environments,
such as
found downhole in wellbores.
Depending on a specific arrangement, multiple optical sensors 30 may be
employed, attached to the outer surface 7 by multiple sensor carriers 25, so
that the
optical sensors 30 may be distributed on a common one of the fibers or
distributed
among multiple fibers. Additionally, the fibers may be encased in protective
coatings,
and may be deployed in fiber delivery equipment, as is well known in the art.
The one or more sensor carrier(s) 25 may be attached to the outer surface 7 by
any method known by those skilled in the art in which the one or more sensor
carrier(s)
25 provides adequate protection to the one or more optical sensor(s) 30 and
effectively
attaches the one or more optical sensor(s) to the outer surface 7. In one
embodiment,
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the sensor carrier 25 is welded to the outer surface 7. In another embodiment,
the
sensor carrier 25 is clamped firmly to the outer surface 7 of the casing
string 5 and may
be cemented into place.
Disposed at a surface 65 of the wellbore 10 is a wellhead 50 through which the
casing string 5 and other tools and components used during wellbore operations
are
lowered into the wellbore 10. Also located at the surface 65 is a signal
interface 60.
The optical cable 55 is connected to the signal interface 60 at the opposite
end from its
connection to the optical sensor 30.
The signal interface 60 may include a broadband light source, such as a light
emitting diode (LED), and appropriate equipment for delivery of signal light
to the Bragg
gratings formed within the core of the optical fibers. The signal interface 60
may further
include logic circuitry, which encompasses any suitable circuitry and
processing
equipment necessary to perform operations described herein, including
appropriate
optical signal processing equipment for receiving and/or analyzing the return
signals
(reflected light) from the one or more optical sensors 30 transmitted via the
one or more
optical cables 55. For example, the logic circuitry may include any
combination of
dedicated processors, dedicated computers, embedded controllers, general
purpose
computers, programmable logic controllers, and the like. Accordingly, the
logic circuitry
may be configured to perform operations described herein by standard
programming
means (e.g., executable software and/or firmware).
Below the optical sensor 30, the fibers may be connected to other sensors (not
shown) disposed along the casing string 5, terminated, or connected back to
the signal
interface 60. While not shown, the one or more cables 55 may also include any
suitable combination of peripheral elements (e.g., optical cable connectors,
splitters,
etc.) well known in the art for coupling the fibers.
The one or more optical sensors 30 may include pressure, temperature,
acoustic, seismic, velocity, or speed of sound sensors, or any other suitable
sensors for
measuring the desired parameters within the wellbore 10 or the formation 15.
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pressure and temperature (P/T) sensors may be similar to those described in
detail in
commonly-owned U.S. Patent No. 5,892,860, entitled "Multi-Parameter Fiber
Optic
Sensor For Use In Harsh Environments", issued Apr. 6, 1999. When using a
velocity
sensor 103 or speed of sound sensor, the optical sensor 30 may be similar to
those
described in commonly-owned U.S. Patent No. 6,354,147, entitled "Fluid
Parameter
Measurement in Pipes Using Acoustic Pressures", issued Mar. 12, 2002. When
using a
seismic sensor or acoustic sensor, the optical sensor 30 may be similar to the
Bragg
grating sensor described in commonly-owned U.S. Patent Number 6,072,567,
entitled
"Vertical Seismic Profiling System Having Vertical Seismic Profiling Optical
Signal
Processing Equipment and Fiber Bragg Grafting Optical Sensors", issued June 6,
2000.
Figure 2 depicts an alternate embodiment of the present invention. A casing
string 105 includes individual mandrels or casing sections 105A, 105B, and
105C,
which are preferably threadedly connected to one another. The casing string
105 may
include three casing sections 105A-C, as shown, or may include any other
number of
casing sections threadedly connected to one another. Alternatively, one casing
section
105B may constitute an embodiment of the present invention. The casing string
105
has an inner surface 106 and an outer surface 107.
The casing string 105 is disposed within a wellbore 110 located within a
formation 115. A physically alterable bonding material 120, preferably cement,
may be
disposed around the outer surface 107 of the casing string 105 to set the
casing string
105 within the wellbore 110. The physically alterable bonding material 120 is
set in an
annulus between the outer surface 107 and an inner diameter of the wellbore
110.
At a surface 165 of the wellbore 110 is a wellhead 150. Also at the surface
165
is a signal interface 160, to which an optical cable 155 is connected. The
signal
interface 160, optical cable 155, and wellhead 150 include substantially the
same
components and perform substantially the same functions as the signal
interface 60,
optical cable 55, and wellhead 50 of Figure 1, so the above discussion
regarding these
components of Figure 1 applies equally to the components of Figure 2.
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One or more of the casing sections 105A-C include one or more protective
pockets 111 around the outer surface 107 of the casing sections 105A, B,
and/or C.
Alternatively, although not shown, the one or more protective pockets 111 may
be
located around the inner surface 106 of the casing sections 105A, B, and/or C.
Figure
2 shows a protective pocket 111 disposed around the outer surface 107 of the
casing
section 105B. The protective pocket 111 is a tubular-shaped mandrel which is
preferably built into the casing section 105B, so that the casing section 105B
may
conveniently be placed within the casing string 105 by threaded connection and
thus
made readily usable. The protective pocket 111 may be welded at the connection
points to the outer surface 107 of the casing section 105B. In an alternate
method of
attachment to the casing section 105B, the protective pocket 111 may be
threaded onto
the outer surface 107 of the casing section 105B.
Housed within the protective pocket 111 is at least one optical sensor 130,
which
is disposed around the outer surface 107 of the casing string 105. The optical
sensor
130 performs substantially the same functions, has substantially the same
characteristics, and is configured in substantially the same manner as the
optical
sensor 30 described above in relation to Figure 1; therefore, the above
discussion
regarding the optical sensor 30 applies equally to the optical sensor 130. The
optical
cable 155 connects the optical sensor 130 to the signal interface 160 to
communicate
information gathered from within the wellbore 110 and/or the formation 115
from the
optical sensor 155 to the signal interface 160, as well as to transmit signals
from the
light source located within the signal interface 160 to the optical sensor
130. To
connect the optical sensor 130 to the signal interface 160, the optical cable
155 runs
through the protective pocket 111 at a predetermined location.
An alternate embodiment of the present invention is shown in Figure 3. A
casing
string 205, which may include one or more casing sections threadedly connected
to one
another, is disposed within a wellbore 210 located within a formation 215. The
casing
string 205 may be set within the wellbore 210 using a physically alterable
bonding
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material 220 as described above in relation to Figure 1. The casing string 205
has an
inner surface 206 and an outer surface 207.
A wellhead 250 located at a surface 265 of the wellbore 210, a signal
interface
260, and an optical cable 255 are substantially similar in configuration,
operation, and
function to the wellhead 50, signal interface 60, and optical cable 55
described above in
relation to Figure 1; accordingly, the above discussion applies equally to the
wellhead
250, signal interface 260, and optical cable 255 of Figure 3. However, an
optical cable
255 of Figure 3 runs through a wall of the casing string 205, between the
inner surface
206 and the outer surface 207 of the casing string 205, rather than outside
the outer
surface 207 of the casing string as depicted in Figure 1.
In the embodiment shown in Figure 3, an optical sensor 230 is at least
partially
embedded within the wall of the casing string 205 between the inner surface
206 and
the outer surface 207 of the casing string 205. The optical sensor 230 as well
as the
optical cable 255 may be placed within the wall of the casing string 205 when
the
casing string 205 is constructed. A casing section may house the optical
sensor 230
within its wall, so that the casing section may be readily threadedly
connected to other
casing sections which may or may not have optical sensors 230 located therein,
to form
the casing string 205. The optical sensor 230 is substantially the same as the
optical
sensor 30, so that the above discussion applies equally to the optical sensor
230.
Figure 4 shows a further alternate embodiment of the present invention similar
to
Figure 1, but with a different location of a sensor carrier 325, optical
sensor 330, and
optical cable 355 in relation to the casing string 305. As illustrated in
Figure 4, the
sensor carrier 325 is attached to the inner surface 306 of the casing string
305. The
optical sensor 330 is disposed within the sensor carrier 325, and thus
disposed around
the inner surface 306 of the casing string 305. The optical cable 355 may run
from the
optical sensor 330, through the wall of the casing string 305, up by the outer
surface
307 of the casing string 305, and to the signal interface 360.
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As described above, the sensor carrier 325 may be welded to the inner surface
306 of the casing string 305, or in the alternative, clamped firmly onto the
inner surface
306. The sensor carrier 325 protects the optical sensor 330 within its housing
from
conditions within the wellbore 310, as well as attaches the optical sensor 330
to the
casing string 305.
Another embodiment of the present invention is illustrated in Figure 5,
including
a casing string 405 with an inner surface 406 and an outer surface 407, and an
optical
sensor 430 attached to the outer surface 407. In this embodiment, there is no
sensor
carrier 25 as in the embodiment of Figure 1. The optical sensor 430 is welded
or firmly
clamped directly to the outer surface 407 of the casing string 405. The casing
string
405 with the optical sensor 430 attached to its outer surface 407 may be
permanently
set within the wellbore 410 with the physically alterable bonding material
420,
preferably cement.
Although not depicted, the optical sensor 430 may be directly attached to the
inner surface 406 in the same way as described above in relation to its
attachment to
the outer surface 407. In this embodiment, the optical cable 455 may be routed
from
the optical sensor 430 through the casing string 405 and alongside the outer
surface
407 of the casing string 405 to the signal interface 460.
In the above embodiments, the physically alterable bonding material 420 may be
used to couple the optical sensor(s) 430 (when employing seismic sensors) to
the
formation 415 to allow sensing of formation parameters. In the alternative,
the seismic
sensors may be coupled to the formation 415 by significant contact with the
formation
415. Thus, the above embodiments are advantageous relative to the prior art
production string deployed seismic sensors, which involved complicated and
tenuous
coupling of the sensors to the formation from the production tubing. Also in
the above
embodiments, any number of optical sensors 30, 130, 230, 330, 430 may be
disposed
along the casing string 5, 105, 205, 305, 405, in any combination of
attachment by one
or more sensor carriers 25, 325, attachment by one or more protective pockets
111,
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embedding within the casing string 205 wall, and/or attachment directly to the
casing
string 405. Further, any combination of types of optical sensors 30, 130, 230,
330, 430,
including but not limited to pressure sensors, temperature sensors, acoustic
sensors,
and seismic sensors, may be used along the casing string 5, 105, 205, 305, 405
and
connected to the signal interface 60, 160, 260, 360, 460 by a common optical
cable 55,
155, 255, 355, 455 or by multiple optical cables running from each optical
sensor 30,
130, 230, 330, 430. In the embodiments involving the sensor carriers 25, 325
and the
protective pocket 111, any number of optical sensors 30, 330, or 130 may be
present
within the sensor carrier 25, 325 and/or the protective pocket 111.
The operation of any or all of the embodiments of Figures 1-5 will be
described
with the component numbers of Figure 1, unless otherwise indicated. Initially,
one or
more casing sections are threaded to one another to form the casing string
305. The
casing sections may already have the sensor carrier 25 and/or the sensor
carrier 325,
the protective pocket 111, the embedded optical sensor 230, and/or the optical
sensor
430 attached directly to them, as well as the optical sensor(s) 30, 230
located within the
sensor carrier(s) 25, 325 and/or protective pocket(s) 111. Alternatively, the
optical
sensor(s) 30 may be attached after the casing string 5 has been assembled from
the
casing sections. The attachment of the sensor(s) 30, protective pocket(s) 111,
and/or
sensor carrier(s) 25, 325 may be by welding, firmly clamping, threading onto
the casing
string 5, or by any other method described above or known to those skilled in
the art.
The one or more optical cable(s) 55 is connected at one end to the one or more
optical
sensor(s) 30 and at the other end to the signal interface 60.
A drill string (not shown) having an earth removal member (not shown) at its
lower end is utilized to drill into the formation 15 to a first depth.
Alternatively, the
casing string 5 may have an earth removal member operatively connected to its
lower
end, and the casing string 5 may be used to drill into the formation 15. In
both cases,
drilling fluid is circulated through the drill string or casing string 5 while
drilling to wash
particulate matter including cuttings from the formation 15 up to the surface
65. In the
case of drilling with the drill string, the drill string is retrieved to the
surface 65, and the
CA 02634650 2008-05-30
casing string 5 is lowered into the drilled-out wellbore 10. When drilling
with the casing
string 5, the casing string 5 is already disposed within the wellbore 10 and
remains
therein.
After the casing string 5 is located within the wellbore 10, the physically
alterable
bonding material 20 may be introduced into the inner diameter of the casing
string 5, to
flow out through the lower end of the casing string 5, then up through an
annulus
between the outer surface 7 of the casing string 5 and the inner diameter of
the
wellbore 10. The physically alterable bonding material 20 may be allowed to
fill at least
a portion of the annulus and to cure under hydrostatic conditions to
permanently set the
casing string 5 within the wellbore 10. Figures 1-5 show the casing strings 5,
105, 205,
305, 405 cemented within the wellbore 10, 110, 210, 310, 410, the optical
sensors 30,
130, 230, 330, 430 therefore permanently deployed within the wellbore 10, 110,
210,
310, 410 by use of the casing strings 5, 105, 205, 305, 405.
At this point, the optical sensor 30, when using a seismic sensor, is coupled
to
the formation 15 and therefore is capable of sensing conditions within the
formation 15.
If the optical sensor 30 is a pressure or temperature sensor, the light source
within the
signal interface 60 may introduce a light signal into the optical cable 55.
Then the
optical sensor 30 may be used to transmit these wellbore parameters to the
signal
interface 60. The signal interface 60 is then used to process the measured
parameters
into readable information. In the alternative, processing of wellbore or
formation
parameters into readable information may be accomplished off-site. After
setting the
casing string 5 within the formation 15, the optical sensor 30 is capable of
measuring
wellbore and formation parameters in real time during all subsequent
operations,
including further drilling and completion operations as well as production and
intervention operations.
Seismic Sensing
If the optical sensor 30 is a seismic or acoustic sensor, source of seismic
energy
(not shown) must be present to emit an acoustic or seismic wave into the
formation 15.
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CA 02634650 2008-05-30
The seismic source may be active and controlled, may result from microseismic
events
that can occur naturally, or may be induced by hydrocarbon fluid production-
related
effects. The acoustic wave is then reflected or partially reflected from the
formation 15
into the seismic sensor 30, which detects and measures the acoustic wave
emitted by
the seismic source. One or more seismic sources may emit one or more acoustic
waves that are at least partially reflected at different locations within the
formation 15 to
measure conditions at multiple locations within the formation 15. Seismic data
obtained
with the optical seismic sensor 30 can be used to directly estimate rock
properties,
water saturation, and hydrocarbon content. The operation of an optical seismic
sensor
used while inserting a drill string into a casing string (as well as while the
drill string is
stationary) and the measurements obtained with the optical sensor are
described in co-
pending U.S. Patent Application Serial Number US 20040129424, filed October
01,
2003, filed on the same day as the current application, entitled
"Instrumentation for a
Downhole Deployment Valve".
The seismic source(s) may be located within the wellbore 10 such as in a drill
string used to drill a wellbore of a second depth within the formation 15
(described
below), or may be located at the surface 65 of the wellbore 10. Additionally
or
alternatively, the seismic source(s) may be located within a proximate
wellbore (not
shown). The vibration of the drill string itself during drilling a wellbore of
a second depth
(described below) against the casing string 5 or against the wellbore 10, or
the vibration
of another tool within the wellbore 10, may also constitute the seismic
source(s). As
described above, each seismic source emits an acoustic wave into various
locations
with the formation 15, then the acoustic wave at least partially reflects from
the
locations in the formation 15 back to the seismic sensor 30, which transmits
the
formation 15 parameter to the signal interface 60 through the optical cable
55.
Additionally, each of the seismic sources may transmit an acoustic wave
directly to the
seismic sensor 30 for calibration purposes to account for the time delay
caused by
reflection from the formation 15. The direct transmission of the acoustic wave
is
necessary to process the gathered information and interpret the final image by
deriving
17
CA 02634650 2008-05-30
the distance between the seismic source and the seismic sensor 30 plus the
travel
time.
In a specific application of the present invention, the seismic source may be
located on or within the drill string (not shown) used to drill to a second
depth within the
formation 15 to set a second casing string (not shown) in the formation 15
below the
first casing string 5 or to access the formation 15 below the first casing
string 5 (e.g., to
recover hydrocarbon fluid from an open-hole wellbore drilled below the first
casing
string 5). The seismic source may be located on or in the earth removal member
at the
lower end of the drill string. In the alternative, the seismic source may
constitute the
vibration of the drill string, earth removal member, and/or any other tool
used in drilling
into the formation 15 to a second depth.
In the above application, the drill string is lowered into the inner diameter
of the
casing string 5 through and below the casing string 5. The drill string is
then used to
drill the wellbore to a second depth within the formation 15. Drilling fluid
is circulated
while the drill string is lowered to the second depth. Because the seismic
sensor 30 is
permanently located on, in, or within the casing string 5, formation
parameters may be
constantly measured and updated in real time while lowering the drill string
into the
inner diameter of the casing string 5, as well as while drilling with the
drill string to the
second depth within the formation 15.
If the seismic source is at the surface 65 or within a proximate wellbore,
seismic
conditions may be measured prior to as well as after insertion of the drill
string into the
wellbore 10, so that real time formation conditions may be transmitted to the
surface 65
through acoustic waves emitted from the seismic source and at least partially
reflected
from the formation 15 at one or more locations to the seismic sensor 30, then
through
formation parameters transmitted through the optical cable 55. Regardless of
the
location of the seismic source(s), the optical cable 55 is used to send the
wellbore
parameter measurements to the signal interface 60. The signal interface 60
processes
the information received through the optical cable 55. The operator may read
the
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CA 02634650 2008-05-30
information outputted by the processing unit and adjust the position of the
drill string
during drilling, the composition of the drilling fluid used during drilling
with the drill string,
or any other parameter during the life of the well. In the alternative, the
data may be
interpreted off-site at a data processing center.
Any number of acoustic waves may be emitted by any number of seismic
sources at any angle with respect to the formation 15 and to any location
within the
formation 15. Seismic measurements may be used in the above embodiments to
monitor the drilling-induced vibrations of the drill string to possibly
evaluate drilling
conditions within the formation 15, such as wear of the earth removal member
or drill
bit, type of rock that makes up the formation 15, and/or smoothness of
drilling.
Measuring Flow While Drilling
Figure 6 shows another embodiment of the present invention. A flow meter 575
is threadedly connected to casing sections above and/or below the flow meter
575 to
form a casing string 505. The casing string 505, which has an inner surface
506 and an
outer surface 507, is shown set within a wellbore 510. The wellbore 510 has
been
drilled out of a formation 515. The casing string 505 may be set within the
wellbore 510
by introducing a physically alterable bonding material 520, preferably cement,
into an
annulus between the outer surface 507 of the casing string 505 and the inner
diameter
of the wellbore 510, and allowing the physically alterable bonding material
520 to cure
under hydrostatic conditions to permanently set the casing string 505 within
the
wellbore 510.
A wellhead 550 may be located at a surface 565 of the wellbore 510. Various
tools, including the casing string 505 and a drill string 580 (described
below) may be
lowered through the wellhead 550. A signal interface 560 is also present at
the surface
565. The signal interface 560 may include a light source, delivery equipment,
and logic
circuitry, including optical signal processing, as described above in relation
to the signal
interface 60 of Figure 1. An optical cable 555, which is substantially the
same as the
19
CA 02634650 2008-05-30
optical cable 55 described above in relation to Figure 1, is connected at one
end to the
signal interface 560.
The flow meter 875 may be substantially the same as the flow meter described
in co-pending U.S. Patent Number 6,945,095, entitled "Non-Intrusive Multiphase
Flow
Meter" and filed on January 21, 2003. Other flow meters may also be useful
with the
present invention. The flow meter 575 allows volumetric fractions of
individual phases
of a multiphase mixture flowing through the casing string 505, as well as flow
rates of
individual phases of the multiphase mixture, to be found. The volumetric
fractions are
determined by using a mixture density and speed of sound of the mixture. The
mixture
density may be determined by direct measurement from a densitometer or based
on a
measured pressure difference between two vertically displaced measurement
points
and a measured bulk velocity of the mixture, as described in the above patent.
Various
equations are utilized to calculate flow rate and/or component fractions of
the fluid
flowing through the casing string 505 using the above parameters, as disclosed
and
described in the above patent.
In one embodiment, the flow meter 575 may include a velocity sensor 591 and
speed of sound sensor 592 for measuring bulk velocity and speed of sound of
the fluid,
respectively, up through the inner surface 506 of the casing string 505, which
parameters are used in equations to calculate flow rate and/or phase fractions
of the
fluid. As illustrated, the sensors 591 and 592 may be integrated in single
flow sensor
assembly (FSA) 593. In the alternative, sensors 591 and 592 may be separate
sensors. The velocity sensor 591 and speed of sound sensor 592 of FSA 593 may
be
similar to those described in commonly-owned U.S. Patent Number 6,354,147,
entitled
"Fluid Parameter Measurement in Pipes Using Acoustic Pressures", issued March
12,
2002.
The flow meter 575 may also include combination pressure and temperature
(P/T) sensors 514 and 516 around the outer surface 507 of the casing string
505, the
sensors 514 and 516 similar to those described in detail in commonly-owned
U.S.
CA 02634650 2008-05-30
Patent Number 5,892,860, entitled "Multi-Parameter Fiber Optic Sensor For Use
In
Harsh Environments", issued April 6, 1999. In the alternative, the pressure
and
temperature sensors may be separate from one another. Further, for some
embodiments, the flow meter 575 may utilize an optical differential pressure
sensor (not
shown). The sensors 591, 592, 514, and/or 516 may be attached to the casing
string
505 using the methods and apparatus described above in relation to attaching
the
sensors 30, 130, 230, 330, 430 to the casing strings 5, 105, 205, 305, 405 of
Figures 1-
5.
Embodiments of the flow meter 575 may include various arrangements of
pressure sensors, temperature sensors, velocity sensors, and speed of sound
sensors.
Accordingly, the flow meter 575 may include any suitable arrangement of
sensors to
measure differential pressure, temperature, bulk velocity of the mixture, and
speed of
sound in the mixture. The methods and apparatus described herein may be
applied to
measure individual component fractions and flow rates of a wide variety of
fluid
mixtures in a wide variety of applications. Multiple flow meters 575 may be
employed
along the casing string 505 to measure the flow rate and/or phase fractions at
various
locations along the casing string 505.
The flow meter 575 may be configured to generate one or more signals
indicative of mixture density and speed of sound in the mixture. For some
embodiments, a conventional densitometer (e.g., a nuclear fluid densitometer)
may be
used to measure mixture density as illustrated in Figure 3 of the above patent
(Serial
Number 6,945,095) and described therein. However, for other embodiments,
mixture
density may be determined based on a measured differential pressure between
two
vertically displaced measurement points and a bulk velocity of the fluid
mixture, also
described in the above patent (Serial Number 6,945,095). The signal interface
560 is
configured to determine flow rate and/or volumetric phase fractions based on
the
signals generated by the flow meter 575, for example by using the equations
described
in the above patent (Serial Number 6,945,095).
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CA 02634650 2008-05-30
Also depicted in Figure 6 is a drill string 580. The drill string 580 includes
a
tubular 582 having an earth removal member 581 attached to its lower end. The
earth
removal member 581 has passages 583 and 584 therethrough for use in
circulating
drilling fluid F1 while drilling into the formation 515 (see below).
In use, the flow meter 575 is placed within the casing string 505, e.g., using
the
previously described technique of threaded connection to other casing
sections. The
casing string 505 may also include casing sections including one or more of
the sensor
arrangements described above and shown in Figures 1-5 to simultaneously
measure
wellbore or formation parameters such as pressure, temperature, seismics,
and/or
acoustics, while also measuring flow rate and/or component fractions with one
or more
flow meters 575.
The wellbore 510 is drilled to a first depth with a drill string (not shown).
The drill
string is then removed. The casing string 505 is then lowered into the drilled-
out
wellbore 510, and physically alterable bonding material 520 may be introduced
in the
annulus and allowed to cure at hydrostatic conditions to set the casing string
505
permanently within the wellbore 510, as described above in relation to Figure
1.
The flow meter 575 is now permanently installed within the wellbore 510 with
the
casing string 505 and is capable of measuring formation or wellbore parameters
which
allow calculation by the signal interface 560 of fluid flow and component
fractions
present in the fluid flowing through the inner diameter of the casing string
505 during
wellbore operations. If employing additional sensors in, on, or within the
casing string
505 according to the embodiments of Figures 1-5, other formation and wellbore
parameters may be simultaneously measured via pressure, temperature, seismic,
or
acoustic optical sensors, as described above.
Often, the wellbore 510 is drilled to a second depth within the formation 515.
As
shown in Figure 6, the drill string 580 is inserted into the casing string 505
and used to
drill into the formation 515 to a second depth. During the drilling process,
it is
customary to introduce drilling fluid F1 into the drill string 580. The
drilling fluid F1 flows
22
CA 02634650 2010-12-07
down through the drill string 580, as indicated by the arrows labeled F1, then
out
through the passages 583 and 584. After exiting the passages 583 and 584, the
drilling
fluid F1 mingles with the particulate matter including cuttings produced from
drilling into
the earth formation 515, then carries the particulate matter including
cuttings to the
surface 565 by the fluid mixture F2, which includes the drilling fluid F1 and
the
particulate matter. The fluid mixture F2 flows to the surface 565 through an
annulus
between the outer diameter of the drill string 580 and the inner surface 506
of the
casing string 505, as indicated by the arrows labeled F2. The drilling fluid
F1 is
ordinarily introduced in order to clear the wellbore 510 of the cuttings and
to ease the
path of the drill string 580 through the formation 515 during the drilling
process.
While the fluid mixture F2 is circulating up through the annulus between the
drill
string 580 and the casing string 505, the flow meter 575 may be used to
measure the
flow rate of the fluid mixture F2 in real time. Furthermore, the flow meter
575 may be
utilized to measure in real time the component fractions of oil, water, mud,
gas, and/or
particulate matter including cuttings, flowing up through the annulus in the
fluid mixture
F2. Specifically, the optical sensors 591, 592, 514, and 516 send the measured
wellbore parameters up through the optical cable 555 to the signal interface
560. The
optical signal processing portion of the signal interface 560 calculates the
flow rate and
component fractions of the fluid mixture F2, as described in the above patent
(Serial
Number 6,945,095) utilizing the equations and algorithms. This process is
repeated for
additional drill strings and casing strings.
By utilizing the flow meter 575 to obtain real-time measurements while
drilling, the
composition of the drilling fluid F1 may be altered to optimize drilling
conditions, and the
flow rate of the drilling fluid F1 may be adjusted to provide the desired
composition
and/or flow rate of the fluid mixture F2. Additionally, the real-time
measurements while
drilling may prove helpful in indicating the amount of cuttings making it to
the surface
565 of the wellbore 510, specifically by measuring the amount of cuttings
present in the
fluid mixture F2 while it is flowing up through the annulus using the flow
meter 575, then
23
CA 02634650 2008-05-30
measuring the amount of cuttings present in the fluid exiting to the surface
565. The
composition and/or flow rate of the drilling fluid F1 may then be adjusted
during the
drilling process to ensure, for example, that the cuttings do not accumulate
within the
wellbore 510 and hinder the path of the drill string 580 through the formation
515.
While the sensors 591, 592, 514, 516 are preferably disposed around the outer
surface 507 of the casing string 505, it is within the scope of the invention
for one or
more of the sensors 591, 592, 514, 516 to be located around the inner surface
of the
casing string 505 or embedded within the casing string 505, as described above
in
relation to Figures 1-5.
Measuring Flow While Drilling with Casing
Figure 7 shows an alternate embodiment of the present invention. Most
components are substantially the same in Figure 7 (indicated by the "600"
series) as
the components in the "500" series of Figure 6. This embodiment differs from
the
embodiment of Figure 6 because the casing string 605 has an earth removal
member
621 operatively connected thereto. The earth removal member 621 is used to
remove
portions of the formation 615 to form a wellbore 610. The casing string 605 is
thus
placed within the wellbore 610 while drilling into the formation 615.
To allow drilling fluid F1 circulation while drilling, the earth removal
member 621
includes passages 623 and 624 therethrough. The drilling fluid F1 is
introduced into the
casing string 605 while drilling through the formation 615, then exits through
the
passages 623 and 624. Cuttings and other particulate matter then are swept
into the
drilling fluid F1 to form the fluid mixture F2 which flows to the surface 665
via an
annulus between the casing string 605 and the inner diameter of the wellbore
610. The
flow meter 675 measures the flow rate and component fractions of the fluid
mixture F2,
as described above, and sends the information to the signal interface 660 via
the
optical cable 655 for processing.
24
CA 02634650 2008-05-30
Once the casing string 605 is installed into place within the wellbore 610,
the
sensors 691, 692, 614, 616 may be utilized to measure the flow rate and/or
component
fractions of the fluid mixture flowing up through an annulus between the
subsequent
drill string (not shown) or the subsequent casing string with the earth
removal member
attached thereto (not shown). Prior to drilling with the subsequent casing
string or drill
string, the earth removal member 621 may be retrieved from the wellbore 610
after its
removal from the casing string 605. In the alternative, the subsequent casing
string or
drill string may drill through the earth removal member 621 prior to drilling
to a second
depth within the formation 615. In addition to the flow meter 675, the casing
string 605
may include any of the embodiments described in Figures 1-5 to employ other
types of
sensors for other types of measurements, such as seismic, acoustic,
temperature,
and/or pressure. These wellbore and formation parameters may be continuously
measured after lowering the casing string 605 into position within the
wellbore 610,
including during the drilling process with the subsequent drill string(s) or
subsequent
casing string(s). In this manner, the flow meter 675 and/or other sensor
arrangements
of Figures 1-5 may be permanently employed within the wellbore 610 to obtain
real time
measurements during all wellbore operations, including the drilling and
completion
operations described at length above.
Several applications of the present invention are envisioned. Temperature,
pressure, seismic, acoustic, and flow measurements may all be utilized to
adjust
parameters while drilling with a drill string or drilling with casing when the
appropriate
sensor(s) is placed on, in, or within the casing string 5, 105, 205, 305, 405,
505, or 605.
Temperature, pressure, and flow measurements obtained in the present invention
may
aid in determining whether an underbalanced states has been reached within the
wellbore, permitting adjustment of wellbore conditions to prevent blowout.
Additional applications of the present invention are contemplated that are
specific to using one or more seismic sensors as the one or more optical
sensors 30,
130, 230, 330, or 430 described in reference to Figures 1-5 and installing the
seismic
sensors with the casing string 5, 105, 205, 305, 405 within the wellbore 10,
110, 210,
CA 02634650 2008-05-30
310, 410. Before the wellbore is drilled into the formation into which the
casing string is
set, seismic data is often gathered from the surface to determine formation
parameters
prior to drilling the well. The seismic measurements from the surface may be
calibrated
by the seismic measurements obtained by the seismic sensor(s) installed with
the
casing string.
Additionally, real time seismic measurements may be taken while drilling into
the
formation during the completion operation. Specifically, imaging ahead of the
earth
removal member of the subsequent casing string or drill string may aid in
determining
the direction in which the earth removal member should be steered
(geosteering).
Various parameters may be adjusted by taking into account the real time
seismic
measurements obtained while drilling to troubleshoot as well as obtain maximum
production from the well. Pore pressure prediction is also possible using the
real time
seismic measurements during drilling.
Acoustic monitoring while drilling into the formation is also an advantageous
application of the present invention. The vibration of the drill string,
including the
attached earth removal member, as well as other tools within the casing string
may be
monitored and adjusted. Acoustics relating to drilling fluids may be monitored
with the
present invention. The present invention allows monitoring of acoustic signals
from the
wellbore having the casing string permanently disposed therein, or monitoring
of
acoustic signals from an adjacent wellbore.
In addition to improving seismic and acoustic monitoring of wellbore
conditions
during drilling, seismic and acoustic monitoring is possible during subsequent
wellbore
operations with the permanently deployed seismic and acoustic sensors with the
casing
string. During production, the same sensors which were employed to measure
parameters during the completion operation may be utilized, as they are
permanently
installed within the wellbore. Therefore, microseismic monitoring as well as
other
acoustic monitoring of production activities is possible with the present
invention.
26
CA 02634650 2008-05-30
Another contemplated use for the present invention is use of the permanently
deployed seismic and/or acoustic sensor(s) for vertical or crosswell seismic
profiling.
The profiling may be 2D, 3D, or 4D, or continuous microseismic monitoring such
as
microseismic profiling, depending upon the dimensions into which the seismic
source
emits the acoustic wave(s), as described above, with the fourth dimension
being time.
Crosswell seismic may be accomplished when the seismic source is located in an
adjacent wellbore by moving the seismic source to accumulate a full image of
the
formation. Microsesimic monitoring allows the operator to detect, evaluate,
and locate
small fracture events related to production operations, such as those caused
by the
movement of hydrocarbon fluids or by the subsidence or compaction of the
formation.
These measurements are useful while drilling as well as after drilling, and
during
completion, production, intervention, and any other operations.
Although the above description of Figures 1-7 discusses cementing the casing
string having the optical sensor attached thereto, it is not necessary in the
present
invention to cement the casing string within the wellbore. Pressure and
temperature
sensing with pressure and temperature optical sensors does not require
coupling to the
formation or cement. Seismic optical sensors do require coupling to the
formation to
measure formation parameters, but this may be accomplished either by cementing
the
casing string to the formation or by placing the seismic sensor into
significant contact
with the wellbore, for example resulting from well deviation or corkscrewing.
When
cementing the casing string within the formation in the above embodiments, the
cement
within the annulus may extend up to a portion of the casing string or to the
upper end of
the casing string or to the surface of the wellbore.
While the foregoing is directed to embodiments of the present invention, other
and further embodiments of the invention may be devised without departing from
the
basic scope thereof, and the scope thereof is determined by the claims that
follow.
27
