Note: Descriptions are shown in the official language in which they were submitted.
CA 02482487 2004-09-24
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 welibores. 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 cemerit 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.
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
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CA 02482487 2004-09-24
, = .
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 welibore, 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
welibore. This method involves attaching a cutting structure in the form of a
drill bit
to the same string of casing which will line the weilbore. 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 welibore 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 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
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CA 02482487 2004-09-24
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
weflbore. Such instruments are either battery operated, or are powered by
electrical
cabies deployed from the surface. The monitoring systems have historically
been
configured to provide an electrical line that ailows 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 opticaf sensor downhole.
The
optical sensor may 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.
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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 wellbore. 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 ernploying seismic sensors
which
need to be coupled 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.
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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 welibore or formation parameters. Iri another aspect, the present
invention provides an apparatus for permanently measuring welibore or
formation
parameters, comprising a casing string permanently located within a wellbore,
and
at least one optical sensor located at least partially wuthin 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.
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
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CA 02482487 2004-09-24
r , = 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.
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.
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CA 02482487 2007-02-06
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 wel(bore 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 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
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CA 02482487 2004-09-24
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, 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
is an optical sensor 30, which is used to sense conditions such as
temperature,
pressure, acoustics, andfor seismic conditions, within the wellbore 10 and the
25 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,
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CA 02482487 2004-09-24
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, 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
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CA 02482487 2007-02-06
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.
The 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.
CA 02482487 2004-09-24
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 ttie above discussion
regarding
these components of Figure 1 applies equally to the components of Figure 2.
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.
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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 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
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CA 02482487 2004-09-24
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
equaliy 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.
As described above, the sensor carrier 325 may be welded to the inner
surface 306 of the casing string 305, or in the alterriative, 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.
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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, 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
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CA 02482487 2004-09-24
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 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
CA 02482487 2007-02-06
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. 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 welibore of a second depth within the formation 15
(described
16
CA 02482487 2004-09-24
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 iriterface 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 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
17
CA 02482487 2004-09-24
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 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 stririg 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
18
CA 02482487 2007-02-06
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 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
19
CA 02482487 2007-02-06
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. 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
CA 02482487 2007-02-06
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).
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 Fl 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 welibore 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
21
CA 02482487 2007-02-06
is customary to introduce drilling fluid Fl into the drill string 580. The
drilling fluid F1
flows down through the drill string 580, as indicated by the arrows labeled
Fl, then
out through the passages 583 and 584. After exiting the passages 583 and 584,
the
drilling fluid Fl 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 Fl
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 Fl
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 disclosed in the above-incorporated application. 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 Fl may be altered to optimize
drilling
conditions, and the flow rate of the drilling fluid Fl 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 measuring the amount of cuttings
22
CA 02482487 2007-02-06
present in the fluid exiting to the surface 565. The composition and/or flow
rate of
the drilling fluid Fl 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.
23
CA 02482487 2004-09-24
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 forrnation 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,
24
CA 02482487 2004-09-24
110, 210, 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 measurerrients 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 weilbore
conditions during drilling, seismic and acoustic monitoring is possible during
subsequent welibore 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 welibore. Therefore,
microseismic monitoring as well as other acoustic monitoring of production
activities
is possible with the present invention.
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.
CA 02482487 2004-09-24
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.
26
