Note: Descriptions are shown in the official language in which they were submitted.
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TITLE OF THE INVENTION
IN-WELL SEISMIC SENSOR CASING COUPLING USING NATURAL FORCES IN
WELLS
s FIELD OF THE INVENTION
This invention relates generally to seismic sensing, and more particularly to
seismic
surveying of an earth formation in, particularly, a deviated, non-linear, or
non-vertical bore
hole.
~o ~ACKGII~OUND OF TI-IE INVENTION
Seismic surveying is a standard tool for the exploration of hydrocarbon
reservoirs. As
is known, seismology involves the detection acoustic waves to determine the
strata of
geologic features, and hence the probable location of oil and/or gas.
Various types of acoustic and/or pressure sensors used in seismology are well
known.
While seismic sensors can be placed on land, or on the bottom or surface of
the ocean, such
sensors may also be placed within the borehole of the well itself. This
approach is generally
known as borehole seismology or vertical seismic profiling (VSP) because the
sensors are
usually arranged substantially vertically within the borehole of the well.
Borehole
seismology may occur within a single well, or may be used in multiple wells,
i.e., a cross-
2o well arrangement, as is well known.
1
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Borehole seismology however is generally somewhat difficult and costly to
perform.
According to some prior art borehole seismology approaches, sensors are only
temporarily
located within the borehole. During this temporary placement, the sensors may
be used to
take readings, and then must be retrieved from the borehole. While the
measurements are
s made, production from the well, if any, might need to be halted, which can
be disruptive and
costly, particularly if measurements are periodically made to assess strata
conditions over a
given time period. Accordingly, because of the time, costs, and hassles
involved with
temporary displacement of sensors, it is generally preferred to permanently
position the
sensors within the borehole, and further preferred that such sensing not
substantially interfere
~o with normal production operations.
Moreover, it is beneficial to mechanically couple certain seismic sensors to
the
borehole, including displacement sensors, geophones, and accelerometers, and
hence the
earth formation of interest. This is because the acoustic waves used in
seismic analysis will
more easily travel to these sensors without attenuation (coupling through
liquids or gases will
~s cause signal attenuation), and because different types of particle motion
(e.g., shear waves)
can be sensed, which is not possible when coupling occurs only through a
liquid or gas.
lElowever, one must go to some effort to affirmatively couple the sensors to
the borehole
structure, usually by active means that can be costly and complex.
It would be beneficial therefore to deploy a sensor down in borehole in a
manner that
2o would naturally (i.e., passively) couple itself to the borehole;, i.e.,
that would couple without
further intervention by the production engineer. It would further be
beneficial for such a
deployment to be suitable for use within deviated (i.e., curved, non-vertical,
non-straight)
wells, as prior art techniques may experience problems in dealing with such
wells. For
example, in deviated, non-linear, or non-vertical wells, sensing apparatuses
may stick, break,
2s or become dislodged in such wells.
2
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The following references, which disclose subject matters to those related
herein, may
be useful to further understand the technology at issue, and/or its
shortcomings, and are
hereby incorporated by reference in their entireties: U.S. Patents 6,072,567;
6,016,702;
5,361,130; 5,401,96; 5,493,390; 5,925,879; 5,767,41 l; PCT Publication No. W~
02/04984.
SUlVINIARY OF TIIE INVENT/ON
A mandrel housing for permanently deploying a seismic sensor or sensor
apparatus
down a well is disclosed. The mandrel is formed integral with or attached to a
pipe and is
incorporatable into the production piping string. The outer diameter of the
mandrel is
~o designed to be slightly smaller than the inside diameter of the well casing
which allows the
mandrel to naturally come into contact with the well casing at points of
deviation, non-
linearity, or non-verticality in the casing. This mechanical coupling of the
mandrel to the
well casing, and hence the earth formation, improves the rf°solution
and type of seismic
signals to be detected by the sensor apparatus. The sensor apparatus fits into
a groove on the
mandrel and is preferably clamped or welded into place or placed within a
tunnel formed in
the mandrel. The mandrel further preferably contains channels on its side to
allow materials
within the annulus to flow around the mandrel even when the mandrel is in
contact with the
casing.
2o BRIEF DESCRIPTION OF T)FIE DRAWINGS
The foregoing and other features and aspects of the present disclosure will be
best
understood with reference to the following detailed description o~f
embodiments of the
invention, when read in conjunction with the accompanying drawings, wherein:
Figure 1 illustrates the placement of production tubing in a deviated well
bore.
Figure 2 illustrates models to estimate the effects of torque and drag.
3
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Figure 3 illustrates an embodiment of the disclosed mandrel deployed in a well
bore
and in contact with the well bore casing.
Figure 4 illustrates an embodiment of the disclosed mandrel and the sensor
apparatus
attached to the mandrel.
Figure 5 illustrates an exemplary method by which the sensor apparatus can be
affixed to the mandrel.
Figure 6A illustrates a cross-sectional view of the mandrel embodiment of
Figure 4.
Figure 6B illustrates a cross-section view of the mandrel in which the
production pipe
is not concentric with the outside diameter of the mandrel.
~o Figure 7 illustrates another exemplary method by which the sensor apparatus
can be
affixed to the mandrel.
Figure 8 illustrates another exemplary method by which the sensor apparatus
can be
affixed to the mandrel.
Figure 9 illustrates a cross-sectional view of an elliptical mandrel
embodiment.
~ s Figure 10 illustrates another exemplary method by which the sensor
apparatus can be
affgxed to the mandrel using a tunnel.
Figure 11 illustrates a cross-sectional view of a mandrel having a polygonal
shape.
Figure 12 illustrates a cross-section view of a mandrel having protrusions.
Figure 13 illustrates a displacement device coupled to a production pipe to
facilitate
zo contact between the disclosed mandrel and the casing.
DETAILED DESCRIPTION OF EMBODIMENTS OF TIIE INVENTION
In the disclosure that follows, in the interest of clarity, not all features
of actual
implementations of a seismic sensing mandrel are described in this disclosure.
It will of course
zs be appreciated that in the development of any such actual implementation,
as in any such
4
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project, numerous engineering and design decisions must be made to achieve the
developers'
specific goals, e.g., compliance with mechanical and business related
constraints, which will
vary from one implementation to another. While attention must necessarily be
paid to proper
engineering and design practices for the environment in question, it should be
appreciated that
s the development of a seismic sensing mandrel would nevertheless be a routine
undertaking for
those of skill in the art given the details provided by this disclosure, even
if such development
efforts are complex and time-consuming.
The disclosed embodiments are particularly useful in seismic surveying using
deviated wells, such as extended reach wells, and horizontal well bores,
although it will also
~o have application in wells exhibiting any degree of non-linearity or slant
(as most wells do) or
even in near-perfectly vertical wells. Deviated, non-linear, or non-vertical
wells present
torque or drag related problems during drilling because the drill string
contacts the low side
of the casing of the borehole. In the same way, torque and drag phenomenon
also occurs
with respect to deployment of a production tube. This is shown generally in
Figure 1, which
15 ShoWS a production tube 1 in contact with a well casing 2 at certain
contact points 3 as
induced by the gravitation influence on the tube 1 and its amount of flexure
within the casing.
The casing 2 can be suitably acoustically coupled to the earth formation or
strata in the
vicinity of the borehole, especially when, as is typical, the casing is
cemented 40 to the
borehole 41.
2o Contact forces for a cylindrical member such as a production tube or
mandrel can be
estimated using well-known torque and drag models. In this regard, Figure 2
shows models
for deriving these parameters, including the "soft string" model (top of
Figure 2) and the
cantilever beam model (bottom of Figure 2). The soft string model involves an
analysis of the
effects of torque and normal force on a cylindrical member under tension. The
cantilever
2s beam model involves an analysis of the effects of bending of the
cylindrical member. An
optimal approach for estimating the true effect of torque and drag can involve
combinations
of these two models, as one skilled in the art will recognize, and the use of
such models may
facilitate the designing or use of the mandrel disclosed herein_
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It has been determined that otherwise inadvertent or unwanted contact between
the
production tube 1 and the casing 2 can provide a suitable mechanical coupling
to allow
sensors on the tube to receive and sense seismic signals. Figure 3 shows such
an
implementation. In Figure 3, mandrels 4 which house seismic sensor apparatuses
7 (not
s shown in Fig. 3) are permanently connected to production tubing l and become
part of the
production string, which is placed within the deviated boxe hole. Figure 3
shows the
mandrels 4 in contact with the well casing 2, which as noted facilitates
seismic sensing by the
sensor apparatus 7. The mandrels 4 are designed, as will be explained in
further detail later,
so that they may be permanently deployed with the production tube 1, and allow
seismic
~o images to be procured over a period of time and without interrupting the
production of oil/gas
from the well. As also will be seen, the mandrels 4 are designed of rigorous
construction,
thus minimizing the possibility of breaking free from the production tube, and
necessitating
premature retrieval of the production tube 1. Moreover, the mandrels are
designed to
passively and naturally come into contact with the casing, and need not be
intentionally or
~s actively adjusted or oriented to establish such contact as in the prior
art. The mandrel design
also provides a simpler housing construction for the sensors over more
traditional downhole
seismic sensing techniques. While two mandrels 4 are shown in Figure 3, one or
more than
two mandrels could also be deployed and brought into contact with the casing
as will be
described herein. In embodiments using fiber-optic-based sensors, there will
preferably be
2o several of the disclosed mandrels which are multiplexed along one or more
fibers to form a
seismic array. In an arrayed embodiment, the mandrels 4 are generally spaced
at set
distances within the well to allow several pick-up points for seismic data
along the length of
the well, thus increasing the extent of the earth formation that can be
assessed.
Figure 4 illustrates an embodiment of the mandrel 4. As shown, the mandrel 4
may
2s comprise or be coupled to pipe ends 20 designed to couple with the
otherwise standard
6
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3105 0016
sections of production tubing 1 at threaded members 6, although other known
methods used
to connect pieces of production piping can be used, such as by clamping. A
premium thread
with suitably high tensile strength, such as a VAt~ Ace certified threaded
connection having
a 233,000-pound minimum tensile capability (based on a VAM Ace Connection),
well-
s known in the art, is suitable. These pipe ends 20 may in turn be similarly
connected to the
mandrel 4 (see for example Fig. 10). Alternatively, the mandrel 4 can slip
over an otherwise
standard section of production tubing 1, and may be bolted, clamped, welded,
or otherwise
fused to the tube 1 through any of several known standard means. Additionally,
the mandrel
4 and associated pipe ends 20 may be milled or forged as an integrated unit.
~ o The inner diameter 5 of the tube contained within the mandrel 4 (or the
tube or pipe
ends to which it is attached or constitutes a part of) is of a size necessary
to allow fluids to
flow to and from the production tubing 1 to which it is coupled and without
impediment
through the tube. In a preferred embodiment, the inner diameter 5 is
substantially the same as
the inner diameter of the otherwise standard sections of production tubing to
which it is
connected, which can vary from well to well as one skilled in the art will
understand.
By contrast, the outer diameter 21 of the mandrel 4 is preferably larger than
the outer
diameter of the production tubing 1, but smaller than the inside diameter of
the casing 2 into
which it will be deployed. Preferably, the outside diameter :Z1 should be just
smaller than
that inside diameter of the casing 2 to ensure a high probability that th.e
mandrel 4 will be
2o brought into contact with the casing 2 at a point of deviation, non-
linearity, or non-verticality
within the well. In this regard, it is well known that casings within a well
are subject to
variation or drift, and accordingly that a particular well can be specified as
having a particular
drift diameter indicative of the smallest extent of the true inside diameter
of the casing. It is
preferred that the outside diameter of the disclosed mandrel be 1/$-inch
smaller than the drift
2s diameter of the casing, although other spacings can be suitable depending
on the nature of the
7
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3105 0016
well environment in question and the degree of deviation, non-linearity, or
non-verticality of
the well. Of course, one skilled in the art will recognize that wells can have
a variety of
diameters, and accordingly that the disclosed mandrel 4 will take on a variety
of different
outside diameters in recognition thereof.
s It is also preferable that the outside diameter 21 be larger than the
outside diameter of
any other structures on or connected to the production pipe l, such as
collars, to ensure that
the mandrel 4 will be brought into contact with the casing 2. As it is desired
for the mandrel
4 to come into contact with the casing 2 at points of deviation, non-
linearity, or non-
verticality, one skilled in the art will understand that the outside diameter
21 of the mandrel
1o will be engineered to function acceptably with a casing 2 inner diameter of
a given value.
The length L of the mandrel and the degree of curvature of the well casing at
points of
deviation, non-linearity, or non-verticality must also be considered when
engineering the
outside diameter 21 of the mandrel to ensure that the mandrel will touch, but
not become
stuck to or damage, the casing 2. A length of approximately 60 inches is
presently preferred
15 for the mandrel 4, although other lengths might be suitable for a given
application. However,
and as one skilled in the art will recognize, it may be desirable in a given
application to make
the mandrel 4 as short as possible to minimize any inherent resonances which
might
interference with the seismic measurements to be made. It i s preferred that
the mandrel be
tapered 25 at its ends to ensure that the mandrel can slip through the casing
2 with relative
2o ease without becoming stuck.
As shown in Figure 4, the mandrel 4 houses a seismic sensor apparatus 7. The
mandrel 4 contains a groove 8 for securely holding the sensor apparatus 7 in
place. The
groove 8 may be milled from the starting material from the mandrel 4, may be
forged, or
formed by many well-known metal-working means. As slhown in Figure 5, the
sensor
25 apparatus 7 preferably has one or more cylindrical housings, and
accordingly the groove 8
8
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3105 0016
preferably has a cylindrical contoL~r. The groove 8 runs preferably along
substantially the
entire length of the mandrel 4 and allows the sensor to be adjusted within the
channel with
about a 5-inch play, which can be beneficial in rnulti-sensor arrays to adjust
the relative
spacing between the sensor apparatuses from mandrel to mandrel.
Many different types of sensor apparatuses may be used in conjunction with the
disclosed mandrel 4. In a preferred embodiment, the sensor apparatus 7
constitutes a sensor
mechanism, such as disclosed in U.S. Patent Application Serial No. 10/266,903,
which is
filed concurrently herewith, is entitled "Multiple Component Sensor
Mechanism," and is
incorporated herein by reference in its entirety. The sensor mechanism
disclosed in this
~o incorporated application includes a cylindrical housing for one or more
sensors. When a fiber
optic based sensor is used, the incorporated sensor mechanism can include one
or m~re
cylindrical housings for splice components, fiber organizers, arid other
devices associated
with optical fiber. Use of the integrated sensor mechanism disclosed in this
incorporated
application is preferred due to the benefits provided by its assembly and its
small, cylindrical
profile, and due to the fact that the sensor mechanism does not need to be
actively deployed
to be brought in contact with the casing, as the mandrel 4 passively serves
this function.
Many different types of sensors can be housed in the sensor apparatus '7 of
the
present invention. Preferably, the sensor constitutes a fiber optic based
sensor containing at
least one fiber Bragg grating. For examplc, the sensor apparatus 7 can have
one or more
2o accelerometers, such as disclosed in U.S. Patent Applications Serial No.
09/410,634, filed
October 1, 1999 and entitled "Highly Sensitive Accelerometer" and Serial No.
10/068,266,
filed February 6, 2002 and entitled "Highly Sensitive Cross Axis
Accelerometer," which are
incorporated herein by reference in their entirety. The accelerometers (not
shown) can be
positioned in any of the three axes (x, y, and z) and can transmit respective
sensing light
2s signals indicative of static and dynamic forces at their location on the
optical fiber.
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3105 0016
Alternatively, the sensor apparatus 7 can constitute other sensors or sensor
systems known in
the art for use in a well.
It should be noted that well-known methods and techniques exist in the art for
processing signals from sensors placed in a deviated, non-linear, or non-
vertical well. For
example, the sensor apparatus 7 can contain three accelerometers arranged in
three
orthogonal axes (x, y, and z) or can contain four accelerometers arranged
along tetrahedral
axes. When the sensor apparatus 7 is positioned in a deviated, non-linear, or
non-vertical
well, and assuming the use of a three-orthogonal-accelerometer arrangement,
the three axes
(x, y, and z) of the sensors will not be oriented to true vertical, and
furthermore will have an
~o unknown rotation. When interpreting the signals, known methods and
techniques can
account for the non-vertical orientation or tilt of the sensors in the well.
For example, when
the well is drilled, the deviation, non-linearity, or non-verticality can be
determined through
Measurement While Drilling (MWD) or well-logging techniques using, for
examples,
magnetometers or gyro tools. As is also known, geophysical methods, such as
polarization
~s analysis of direct arrivals of seismic waves emitted from a known source
location, can be
used to derive the rotated position of the sensors. By knowing tilt and
rotation, the signals
coming form the sensors can be processed or adjusted so that they reflect the
true status of the
earth formation.
The sensor apparatus 7 communicates with a cable 11, which is preferably a
fiber
20 optic cable for those instances in which a fiber optic based sensor
apparatus 7 is used, but
could also constitute a wire if an electrically based sensor apparatus 7 is
used. As shown in
Figure 4, the fiber optic cable 11 emerges from both ends of t:he sensor
apparatus 7. Such a
dual-ended sensor apparatus 7 allow several sensors apparatuses to be
multiplexed in series,
or allows the sensor apparatus 7 to be multiplexed with other downhole fiber
optic measuring
2s devices, such as pressure sensors, temperature sensors, flow rate sensors
or meters, speed of
1~
CA 02444427 2003-10-06
3105 0016
sound or phase fraction sensors or meters, or other like devices. Examples of
such auxiliary
sensing devices are disclosed in the following U.S. Patent Applications, which
are hereby
incorporated by reference in their entireties: Serial No. 10/115,727, filed
April 3, 2002,
entitled "Flow Rate Measurement Using Short Scale Length Pressures"; Serial
No.
s 09./344,094, filed June 25, 1999, entitled "Fluid Parameter Measurement In
Pipes Using
Acoustic Pressures"; Serial No. 09/519,785, filed March 7, 2000, entitled
"Distributed Sound
Speed Measurements For Multiphase Flow Measurement"; Serial No. 10/410,183,
filed Nov.
7, 2001, entitled "Fluid Density Measurement In Pipes Using Acoustic
Pressures"; and Serial
No. 09/740,760, filed November 29, 2000, entitled "Apparatus For Sensing Fluid
In a Pipe."
~o If only one sensor apparatus 7 is used, or for the Iast sensor apparatus 7
in a string, the
fiber optic cable 11 need not proceed through both ends but may be single
ended. Ultimately,
cable 11 proceeds to the surface of the well along the edge of the production
pipe 1 to a
source/sensing/data collection apparatus as is well known, and which is
capable of
interrogating the sensor apparatus 7 and interpreting data retrieved
therefrom.
15 The sensor apparatus 7 may be held firmly within the mandrel 4 by several
means. In
a first embodiment shown in Figures 4 and 5, the sensor apparatus 7 is held
within the
mandrel 4 using hinge clamps 9 hinged to the mandrel 4 a sing hinge rods 13.
The hinge
clamps 9 may be rotated over the sensor apparatus once it is in place and
thereafter may be
bolted to the mandrel 4 at bolt holes 22 by bolts 10. In a second embodiment,
shown in
2o Figure 8, clamps 9 are not hinged, but instead are bolted at both ends to
the mandrel using
bolts 10 as shown. In a third embodiment, shown in Figure 7, clamps 9 may be
welded or
brazed to the mandrel 4 at weld points 23. As it is generally important to
protect the sensor
apparatus 7 from the harsh downhole environment and to protect it fgom
mechanical damage,
it is generally preferred that a secure junction be made between the clamps 9
and the mandrel
2s 4 such as those disclosed herein, although other like mechanisms may be
used. As one
~1
CA 02444427 2003-10-06
3105 0016
skilled in the art will recognize, and depending on the design of the clamp 9,
a single clamp
can be used with a given mandrel 4, or several clamps can be used as shown. If
a single
clamp is used, that clamp can be made to span the entire length of the sensor
apparatus 7,
which might provide optimal sensor protection.
s Other structures to secure the sensor apparatus '~ can be used. For example,
and as
shown in Figure 10, the sensor can fit within a tunnel 17 formed in the side
of the mandrel 4.
The tunnel 17 is preferably milled or drilled into the mandrel 4, and
preferably has a diameter
just slightly larger than the outside diameter of the sensor apparatus 7 such
that the sensor
apparatus 7 slips into but is firmly held by the tunnel 17. In such a tunneled
embodiment, it
15 preferably to place seals 18 at the ends the tunnel 17 to ensure that the
sensor apparatus 7
stays in place when deployed. These seals 18 could be made in any number of
ways as one
skilled in the art will recognize. For example, they could comprise elastomer
seals that press
lit into the ends of the tunnel 17 or screwable seals which mates with threads
form on the
inside of the tunnel.
In a preferred embodiment, and referring to the cross-sectional view of Figure
6A,
channels 12 are formed on the side of the mandrel 4 to allow for the bypass of
fluids or gases
(and some solids of minimal dimension) that might be located in the annulus
between the
production pipe 1 and the casing 2, such as mud, oil/gas, water, or other
caustic drilling
agents. (These channels 12 can also be seen in the illustrative embodiments of
Figures 4 and
2o 5, but are not shown in the other figures for clarity). These channels 12
are preferably milled
from the starting material for the mandrel, but may also be forged, stamped,
or formed by any
other well-known metal-working processes. Although four such channels 12 are
shown in
Figure 6, more of fewer channels could also be formed, and such clcannels
could be made of
differing sizes and shapes. Additionally, the channels 12 need not be
parallel, but could for
2s example be comprised of helical twist grooves, serpentine patterns, etc.
I2
CA 02444427 2003-10-06
' 3105 0016
The tube 5 within the mandrel is preferably concentric with the outer diameter
of the
mandrel 4, as shown in Figure 6A, which facilitates deployment and retrieval
of the mandrel
and maximizes the chance that the mandrel 4 will not inadvertently become
stuck in the
casing. However, the mandrel 4 can be positioned such that it is not
concentric with the tube
5, but instead sits off center, as shown in Figure 6B. This orientation allows
extra room for
the groove 8 or tunnel 17 which houses the sensor apparatus 7, and, despite
the risk of
sticking, may help facilitate mechanical coupling between the mandrel 4 and
the casing 2,
because the inner mandrel tube S will be inclined, by virtue of its connection
to the
production pipe, to generally center itself within the casing 2. Such non-
concentric
~o embodiments may cause a minor degree of flexure in the production pipe,
which rnay not be
desirable in some applications and environments.
Other variations in the topology of the mandrel 4 are possible to allow for
the flow of
fluid around the mandrel in the annulus. Far example, and referring to Figure
9, an elliptical
shape i s provided for the outside surface of the mandrel 4. As with the other
embodiments
15 disclosed herein, the maximum diameter of the ellipse is preferably as
large as possible, e.g.,
1/8 inch short of the inner diameter of the casing, but still small enough to
pass through the
casing 2. The minimum diameter defines a channel 12 allowing for the passage
of fluids or
other materials in the annulus.
The mandrel 4 is preferably as stiff as possible to ensure good acoustic
coupling
2o between the seismic events to be detected and the sensor apparatus 7, but
can be comprised of
any number of materials typically used for downhole tools. High strength, anti-
corrosive
materials, such as stainless steel, are suitable. Construction of the mandrel
using such
materials, and using a 5.5-inch diameter mandrel, will result in a mandrel
component
' weighing about 150-200 pounds. Of course, the design of mandrel 4 is
preferably modified
25 depending on the environment (well) in which it is to be placed, which can
vary from well to
13
CA 02444427 2003-10-06
~1~5 ~~I6
well in terms of their pressures, temperatures, and exposure to caustic
chemicals. The
material of the mandrel 4 may need to be modified if sufficient amounts of
hydrogen sulfide,
or "sour gas," are present, and such sour gas resistant metallurgies are well
known to those of
skill in the art. Additionally, stabilizing or stiffening structures could
also be included within
the mandrel body.
As discussed, it is preferable when making seismic measurements for the
disclosed
mandrel to touch, i.e., mechanically couple to, the casing and hence the earth
formation under
analysis. It is preferable that the mandrel not rock, sway, or torque within
the casing, which
it might be prone to do given the turbulent nature of the downhole
environment. In this
~o regard, other shapes for the mandrel might be employed to improve coupling
and to
maximize the probability of holding the mandrel steady during the receipt of
seismic
measurements. (The above-disclosed "round" mandrels, while believed suitable
for some or
most applications, might function less well in such turbulent environments.)
Accordingly, for those applications requiring firmer mechanical coupling, the
design
Of the mandrel could be changed. ~ne example of such a change is shown in
Figure I1,
which shows a mandrel 4 that is triangular in cross section. As shown in that
Figure, when
the mandrel 4 touches the casing 2, it will touch at the outer points 3I of
the triangular cross
section. Because, as in the other embodiments, the outer diameter of the
triangle (were it
circumscribed in a circle) is just smaller than the drift diameter of the
casing, e.g., by 1/8
2o inch, chances are improved that the mandrel 4 will touch the casing 2 at
two points 31 at a
given cross section, i.e., at two points of the triangle, as shown in Figure I
I. (By contrast, a
circular mandrel will only touch the casing at one point at a given cross
section). Touching
the casing at two points 3I will tend to prevent the mandrel ~. from torquing
or rolling with
respect to the casing 2, and hence may help in a given application to hold the
mandrel
2s steadier with respect to the casing when compared with round mandrel
embodiments. Of
14
CA 02444427 2003-10-06
3105 OOI6
course, other cross sectional shapes may achieve these same beneficial
results, such as
squares, hexagons, etc., and these shapes may also be beneficial in that they
might add
mechanical stability or stiffness to the mandrel. Furthermore, such shapes
will naturally form
channels 12 with respect to the side of the casing to allow for the flow of
materials past the
mandrel in the annulus. Such alternative polygonal cross sections need not be
formed of
straight lines, but could be bowed, as represented by dotted line 28 in Figure
11 (which might
require the positions of the inner pipe and sensor apparatus 7 to be adjusted
within the
mandrel).
The foregoing benefits of these alternative polygonal embodiments can also
~o effectively be realized using an otherwise round mandrel. For example, in
Figure 12, there is
disclosed a mandrel 4 that is otherwise similar t~ the rounded embodiments
disclosed in
Figures 4-10, but includes protrusions 30. The protrusions 30 project radially
from the
mandrel 4 and are designed to contact the casing 2 in much the same way that
the polygonal
embodiments of Figure 11 would, i.e., preferably at two points of contact. The
pr~trusions 30
define, in Figure 12, a hexagon, but other polygonal shapes are possible. The
protrusions
preferably run along the entire length of the mandrel 4, but may also appear
at certain points
along it length, or only at the top and bottom of the mandrel where they are
most likely to
touch. t~lthough not shown, the protrusions 30 may be tapered to reduce the
possibility of
catching on the casing 2 as the mandrel is deployed downhole. The protrusions
30 can be
2o milled from the body material for the mandrel, or may be attached by any
well-known metal-
working techniques, such as brazing, bolting, clamping, etc. A,s with the
other embodiments,
the outer diameter of the protrusions (were they circumscribed in a circle)
are preferably just
smaller than the inner diameter of i:he casing to improve the chances of
mechanical coupling
to the casing. The protrusions may constitute many different shapes suitable
for coupling
2s with the casing, such as rounded bumps, and may comprise different heights
or thicknesses.
CA 02444427 2003-10-06
3105 0016
The foregoing thus discloses a seismic sensing mandrel constructed of minimal
parts,
and which is of a suitably solid construction to house and protect the
preferred fiber optic
sensors disclosed herein. However, the mandrel 4 is also easily adapted to
house more
traditional seismic sensors, such as those that are electrically and/or
mechanically based. The
mandrel is also easily adaptable to house other such structures or their
cabling. For example,
additional channels or tunnels could be formed in the mandrel 4 to allow for
the passage of
additional electric or fiber optic cables. t~s disclosed, the mandrel meets or
exceeds strength
requirements for production tubing.
Figure 13 discloses a design for bringing the mandrel ~G into contact with the
casing 2,
~o again using natural forces. In Figure 13, a displacement device 3S is shown
connected to the
production pipe near the mandrel. The displacement device 35 is designed to
displace the
production pipe from its natural center within the casing, and accordingly has
a radius D2
which is preferably just larger than the average distance DI between the
outside diameter of
the production pipe 1 and the inside diameter of the casing 2. The
displacement device will
generally touch the casing 2 throughout its entire length as the production
pipe 1 and the
mandrel 4 are deployed. To reduce the chance of catching during deployment,
the
displacement device 35 may be tapered as shown. By displacing the production
pipe l, the
mandrel 3 is likewise displaced within the casing 2, improving the chance of
mechanically
coupling the mandrel to the casing. Because the production pipe 1 is somewhat
flexible, both
2o the mandrel 3 and the displacement device 35 should be able to s~.ip
through the casing 2
without issue, with areas of friction or undesirable narrowness in the casing
2 being relieved
by slight bending of the production pipe 1. To ensure that the pipe 1 is not
overstressed or
bent to the point of fracture, it may be desirable to place the displacement
device 35 at a
suitable distance from the mandrel 3. To further reduce such unwanted stresses
on the
production equipment, it may be necessary in some applications to design the
displacement
CA 02444427 2003-10-06
3105 0016
device 35 and the mandrel in highly tapered configurations to reduce the
chances of catching
on the casing. It should be noted that this embodiment may generally cause the
mandrel 3 to
contact the casing even in locations where the casing is perfectly vertical,
and hence
improves the ability of the disclosed mandrel to take sensor measurement even
in non-
s deviated wells or wells of only slight deviation, non-linearity, or non-
verticality. The
displacement device may comprise many known structures, but in a preferred
embodiment
comprises a solid block or fin of steel bolted to the production pipe. Other
structures 35
capable of displacing the production tube 1 and/or the mandrel 4 and methods
for affixing
such structures to the pipe 1 are well within the purview of those skilled in
the art. Although
1o shown above the mandrel 4 on the production pipe, the displacement device
35 will serve the
same function if mounted below the mandrel 4 on the pipe 1. If multiple
mandrels on used
on a given production tube, multiple displacement devices 35 ray be used as
well.
While particularly useful for the deployment of sensors usable for vertical
seismic
analysis, the disclosed mandrel will have utility for the deployment of other
types of sensors
1s as well, such as pressure and temperature sensors. Additionally, while the
disclosed mandrel
is particularly useful in deviated, non-linear, or non-vertical wells, it can
have utility for the
deployment of other sensors that need mechanical rigidity but that would not
necessarily
benefit from contact or mechanical coupling with the well casing.
The term "outside diameter" as it applies to the mandrel should be understood
as
2o referring to the outside diameter of a circle that circumscribes the
mandrel and its
accompanying structures if any. Accordingly, all of the disclosed embodiments
disclosed
herein, be they circular or not, and including those of polygonal cross
section or having
protrusions extending from the hody of the mandrel, should be understood as
having an
"outside diameter." Contacting the mandrel to the well by "natural force"
denotes contact
Zs between the mandrel and the casing without active actuation of any devices
capable of
1~
CA 02444427 2003-10-06
3105 0016
facilitating such contact and without active intervention on the part of the
production
engineer.
1$
