U.S. patent application number 10/178188 was filed with the patent office on 2002-12-05 for method and apparatus for placing and interrogating downhole sensors.
Invention is credited to Bayh, Russell Irving III, Mahjoub, Nadir, Nutley, Brian George, Oag, Jamie George, Robison, Clark Edward, Schultz, Roger Lynn, Stewart, Benjamin Bernhardt III.
Application Number | 20020179301 10/178188 |
Document ID | / |
Family ID | 24472722 |
Filed Date | 2002-12-05 |
United States Patent
Application |
20020179301 |
Kind Code |
A1 |
Schultz, Roger Lynn ; et
al. |
December 5, 2002 |
Method and apparatus for placing and interrogating downhole
sensors
Abstract
A method and system to passively monitor cement integrity and
reservoir/formation parameters near the wellbore at all depths and
orientations outside a wellbore. Different types (pressure,
temperature, resistivity, rock property, formation property etc.)
of sensors are "pumped" into place by placing them into a
suspension in the cement slurry at the time a well casing is being
cemented, by placing them in gravel pack used in frackpacking, or
by a deflected drilling tool. The sensors are either battery
operated, or of a type where external excitation, (EMF, acoustic,
RF etc.) may be applied to power and operate the sensor, which will
send a signal conveying the desired information. The sensor is then
be energized and interrogated using a separate piece of wellbore
deployed equipment whenever it is desired to monitor cement or
formation conditions. This wellbore deployed equipment could be,
for example, a wireline tool.
Inventors: |
Schultz, Roger Lynn;
(Aubrey, TX) ; Robison, Clark Edward; (Plano,
TX) ; Bayh, Russell Irving III; (Carrolton, TX)
; Stewart, Benjamin Bernhardt III; (Aberdeen, GB)
; Nutley, Brian George; (Fareham, GB) ; Oag, Jamie
George; (Aberdeen, GB) ; Mahjoub, Nadir;
(Jacarta, ID) |
Correspondence
Address: |
CARSTENS YEE & CAHOON, LLP
P O BOX 802334
DALLAS
TX
75380
|
Family ID: |
24472722 |
Appl. No.: |
10/178188 |
Filed: |
June 24, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10178188 |
Jun 24, 2002 |
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09617212 |
Jul 17, 2000 |
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6408943 |
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Current U.S.
Class: |
166/250.01 ;
166/113; 166/285; 166/381 |
Current CPC
Class: |
E21B 47/01 20130101;
E21B 7/061 20130101 |
Class at
Publication: |
166/250.01 ;
166/285; 166/381; 166/113 |
International
Class: |
E21B 047/00 |
Claims
We claim:
1. A method of placing sensors in a borehole, the steps comprising:
drilling a borehole with a drill apparatus; forming a well casing
therein; and placing at least one remote sensor into cement slurry
as the well casing is being cemented.
2. The method as recited in claim 1, wherein the at least one
remote sensor comprises a transducer.
3. The method as recited in claim 1, wherein the at least one
remote sensor comprises a pressure measurement device.
4. The method as recited in claim 1, wherein the at least one
remote sensor comprises temperature measurement device.
5. The method as recited in claim 1, wherein the at least one
remote sensor comprises a resistivity measurement device.
6. The method as recited in claim 1, wherein the at least one
remote sensor measures rock properties.
7. The method as recited in claim 1, wherein the at least one
remote sensor measures formation properties.
8. The method as recited in claim 1, wherein the at least one
remote sensor measures paramagnetic properties.
9. The method as recited in claim 1, wherein the at least one
remote sensor measures magnetic fields.
10. The method as recited in claim 1, wherein the at least one
remote sensor measures pulse eddy current.
11. The method as recited in claim 1, wherein the at least one
remote sensor measures polar spin.
12. The method as recited in claim 1, wherein the at least one
remote sensor measures magnetic flux leak.
13. The method as recited in claim 1, wherein the at least one
remote sensor measures well integrity.
14. The method as recited in claim l, wherein the at least one
remote sensor measures casing wear.
15. A method of placing sensors in a geologic formation, the steps
comprising: drilling a wellbore with a drill apparatus; placing a
at least one sensor outside said borehole; and placing a wellbore
device into said wellbore to interrogate said at least one
sensor.
16. The method as recited in claim 15, wherein said at least one
sensor is powered by external excitation.
17. A method of placing sensors in a geologic formation, the steps
comprising: drilling a wellbore with a drill apparatus; removing
formation material in a direction away from said wellbore to
produce a sensor placement area; and placing a sensor into said
sensor placement area.
18. The method as recited in claim 17, wherein said removing
formation material step comprises using a side bore coring
tool.
19. The method as recited in claim 17, wherein said removing
formation material step comprises fracturing and packing the
formation with a slurry and wherein said placing step comprises
placing said sensor in said slurry prior to packing the formation
with said slurry.
20. An apparatus for placing a sensor in a geologic formation,
comprising: a first tube, a second tube attached to said first tube
wherein the end of said second tube opposite from end attached to
said first tube comprises a nozzle for expressing fluid and wherein
said second tube comprises clasping means for attaching a sensor
thereto; and deflectors attached to the outside surface of said
first tube for deflecting said second tube away from said first
tube.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Technical Field
[0002] The present invention relates to a method and apparatus for
placing sensors downhole in a well to monitor relevant formation
characteristics. Specifically, the sensors can be flowed into the
formation in the cement, or other suitable material, used to case
the well. Alternatively, the sensors can be physically bored into
the formation with a device described herein.
[0003] 2. Description of the Related Art
[0004] Understanding an oil-bearing formation requires accurate
knowledge of many conditions, such as critical rock and formation
parameters at various points in the zones or formations that the
oil bearing formation encompasses. Fluid pressure in the formation,
its temperature, the rock stress, formation orientation and flow
rates are a few examples of measurements taken within the formation
which are useful in reservoir analysis. Having these formation/rock
measurements available external to the immediate wellbore in wells
within a producing field would facilitate the determination of such
formation parameters such as vertical and horizontal permeability,
flow regimes outside the wellbores within the formations, relative
permeability, water breakthrough condensate banking, and gas
breakthrough. Determinations could also be made concerning
formation depletion, injection program effectiveness, and the
results of fracturing operations, including rock stresses and
changes in formation orientation, during well operations.
[0005] In addition to understanding oil bearing formations, the
condition of the material used to set casing in a well is of
critical interest in monitoring the integrity of a well completion.
While cement is commonly used to set casing, other materials such
as resins and polymers could be used. So while the term cement is
used in this description, it is meant to encompass other suitable
materials that might be used now or in the future to set casing.
Pressure, temperature and stress, are a few examples of
measurements taken within the cement that might be useful in
determining the condition of the cement in a well. Various types of
transducers placed near the cement/wellbore interface could be used
to monitor the condition of the rock or formations outside the
wellbore. Having these formation/rock measurements available
external to the immediate wellbore in wells within a producing
field would facilitate the determination of such formation
parameters such as vertical and horizontal permeability, flow
regimes outside the wellbores within the formations, relative
permeability, potential fines migration, water breakthrough, and
gas breakthrough. Determinations could also be made concerning
formation depletion, fines migration, injection program
effectiveness, and the results of fracturing operations, including
rock stresses and changes in formation orientation, during well
operations.
[0006] Historically, reservoir analysis has been limited to the use
of formation measurements taken within the wellbores. Measurements
taken within the wellbore are heavily influenced by wellbore
effects, and cannot be used to determine some reservoir parameters.
Well conditions such as the integrity of the cement job over time,
pressure behind the casing, or fluid movement behind the casing
cannot be monitored using the wellbore measurements.
[0007] Therefore, it is desirable to have a method and system that
may be used to passively monitor reservoir/formation parameters at
all depths and orientations outside a wellbore as well as having a
method and system to passively monitor cement integrity. It is
further desirable to have a method and system to take these
measurements without compromising the casing, cement or any other
treatment outside or inside the casing.
SUMMARY
[0008] The present invention provides a method and system that may
be used to passively monitor cement integrity and
reservoir/formation parameters near the wellbore at all depths and
orientations outside a wellbore. These measurements may be taken
without compromising the casing, cement or any other treatment
outside or inside the casing. In addition, sensors may be deployed
in many more locations because of the non-intrusive nature of
reading the sensors once they are in place.
[0009] In one embodiment, different types (pressure, temperature,
resistivity, rock property, formation property etc.) of sensors are
"pumped" into place by placing them into a suspension in the cement
slurry at the time a well casing is being cemented. The sensors are
either battery operated, or of a type where external excitation,
(EMF, acoustic, RF etc.) may be applied to power and operate the
sensor, which will send a signal conveying the desired information.
The sensor may then be energized and interrogated using a separate
piece of wellbore deployed equipment whenever it is desired to
monitor cement or formation conditions. This wellbore deployed
equipment could be, for example, a wireline tool. Having sensors
placed in this way allows many different types of measurements to
be taken from the downhole environment. Looking at readings taken
at different locations will allow directional properties such as
permeability to be examined. Sensors placed close to the wellbore
can be used to monitor the well integrity by disclosing information
about cement condition, casing wear/condition etc. Sensors placed
closer to the cement/wellbore interface provide reservoir or rock
property measurements, which may be used in reservoir analysis.
[0010] In another embodiment, the sensors are placed into the
formation at or outside the wellbore and may be interrogated
whenever it is desired to monitor well or formation conditions. One
method of placing the sensors into the formation is to use
technology similar to side bore coring tools which remove samples
in a direction that is perpendicular to the wellbore. Another
method involves placing the sensors into the gravel slurry used for
gravel packing and frackpacking operations thus allowing the
sensors to migrate into the formation with the fracpack.
[0011] There are many advantages of the proposed system. First,
non-intrusive downhole measurements may be taken from numerous
locations in the downhole environment. Next, the integrity of the
cement job can be closely monitored for initial quality, and
degradation with time. Further, many transducers may be placed into
the well with relatively low deployment cost. Also, very accurate
measurements can be taken because of transducer placement outside
the wellbore. Also, very long service life of transducers is
achieved because power is supplied by a wellbore device capable of
supplying transducer excitation power. Finally, fluid movement and
pressure behind the casing may be measured by comparing the many
available downhole measurements.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The novel features believed characteristic of the invention
are set forth in the appended claims. The invention itself,
however, as well as a preferred mode of use, further objectives and
advantages thereof, will best be understood by reference to the
following detailed description of an illustrative embodiment when
read in conjunction with the accompanying drawings, wherein:
[0013] FIG. 1 shows a flow chart for placing sensors within the
cemented casing of a wellbore.
[0014] FIG. 2 depicts a wellbore with sensors located within the
cemented casing.
[0015] FIG. 3 shows a flow chart for placing sensors into the
formation.
[0016] FIG. 4 depicts a wellbore and formation with sensors located
in the formation.
[0017] FIG. 5 shows a flow chart for placing a sensor into a
formation by drilling laterally away from a wellbore.
[0018] FIGS. 6A-6C depict a tool for drilling away from a wellbore
and placing a sensor into a formation.
DETAILED DESCRIPTION
[0019] A presently preferred embodiment of the present invention
for placing sensors into a wellbore casing will now be described
with reference to FIGS. 1 and 2. FIG. 1 shows a flowchart of a
preferred embodiment of a method for placing sensors into a
wellbore casing. FIG. 2 illustrates a cross-sectional view of a
wellbore and casing with sensors placed therein.
[0020] A wellbore 240 is drilled into the earth using conventional
methods and tools well known to those skilled in the art (step
110). Sensors 210 are placed into a cement slurry (step 120). A
casing is placed into wellbore 240 and the cement slurry containing
sensors 210 is pumped into wellbore 240 to provide a cemented
casing 240 (step 130). A wellbore device (not shown in FIG. 2) is
then placed into wellbore 240 (step 140). Sensors 210 are then
interrogated with the well bore device (step 150). The wellbore
device could be for example a wireline tool or a drill pipe
conveyed system. Sensors 210 will typically be transducers which
are either battery operated, or of a type where external excitation
(EMF, acoustic, RF, etc.) may be applied to power and operate the
transducer, which will send a signal conveying the desired
information. Sensors 210 may be interrogated whenever desired to
monitor cement or formation conditions. Sensors 210 may be of many
different types such that many different types of conditions may be
monitored. Such monitored conditions include pressure, temperature,
resistivity, rock properties, and formation properties. Other
monitored conditions include, but are not limited to, paramagnetic
properties, magnetic fields, magnetic flux leak, pulse eddy
current, and polar spin. Looking at different readings taken at
different locations will allow directional properties such as
permeability to be examined. Sensors 210 placed close to the
wellbore can be used to monitor the well integrity by disclosing
information about cement condition, casing wear/condition etc.
Sensors 210 placed closer to the cement/wellbore interface provide
reservoir or rock property measurements which may be used in
reservoir analysis.
[0021] There are many advantages to placing sensors within the
cemented well casing. Non-intrusive downhole measurements may be
taken from numerous locations in the downhole environment. The
integrity, such as micro-annulus, of the cement job can be closely
monitored for initial quality and degradation with time. Many
sensors may be placed into the well with relatively low deployment
cost. Very accurate measurements can be taken because of sensor
placement outside of the wellbore. Very long service life of the
sensors because the power is supplied by a wellbore device capable
of supplying transducer excitation power. Fluid movement and
pressure behind the casing may be measured by comparing the many
available downhole measurements.
[0022] Turning now to FIGS. 3 and 4, a method of placing sensors
into a formation will be described. FIG. 3 depicts a flow chart for
a presently preferred method of placing sensors into a formation.
FIG. 4 shows a cross-sectional view of a well bore and formation
with sensors located within the formation.
[0023] A wellbore 440 is drilled using conventional techniques and
devices well known to one skilled in the art (step 310). Formation
samples are removed from the formations 420, 425, and 430 using for
example, a side bore coring tool, in a direction perpendicular to
wellbore 440 (step 320). The maximum distance bored out with
standard coring tools is typically around 4 feet from the wellbore
440. One example of a side bore coring tool may be found in U.S.
Pat. No. 5,209,309 issued to Wilson which is hereby incorporated by
reference. Sensors 410 are then placed into the formations 420,
425, and 430 (step 330). A sensor interrogating device is then
placed into the wellbore (step 340). Sensors 410 are then
interrogated whenever it is desired to gather some information that
sensors 410 can gather (step 350).
[0024] In one variation of this method, rather than removing
formation samples with a side bore coring tool, the formations 420,
425, and 430 are fractured and packed with gravel ("fracpacking").
Sensors 410 are placed in the gravel slurry prior to packing the
fracture. Thus, sensors 410 are placed outside the wellbore and
into the formation. Alternatively, perforations 460 can be made in
the wellbore 440 casing and the sensors 410 allowed to migrate
outside the wellbore 440 with the gravel slurry. The gravel slurry
and fracpacking will be described in more detail below.
[0025] As with sensors 210, sensors 410 will typically be
transducers which are either battery operated, or of a type where
external excitation (EMF, acoustic, RF, etc.) may be applied to
power and operate the transducer, which will send a signal
conveying the desired information. Alternatively, the sensors 410
may be powered using fuel cell or power cell. The fuel cell or
power cell may be part of the sensors 410 or built as an addition.
Formation movement, noise or fluid flow (i.e. effluent flow) could
be used to charge or recharge the cell power source. Sensors 410
may be interrogated whenever desired to monitor cement or formation
conditions. Sensors 410 may be of many different types such that
many different types of conditions may be monitored. Such monitored
conditions include pressure, temperature, resistivity, rock
properties, and formation properties. Other monitored conditions
include, but are not limited to, paramagnetic properties, magnetic
fields, magnetic flux leak, pulse eddy current, and polar spin.
Sensors 410 placed close to the wellbore 440 can be used to monitor
the well integrity by disclosing information about cement
condition, casing wear/condition etc. Sensors 410 placed further
into a formation or other surrounding substrate will provide very
accurate reservoir or rock property measurements.
[0026] It should be noted that sensors 210 and 410 may be
calibrated before placement and may be recalibrated after placement
in the formation or well casing. For example, a radio or acoustic
signal may be sent to each or sensors 210 or 410, after placement,
initiating a calibration response in each of sensors 210 or
410.
[0027] There are many advantages to placing sensors outside the
wellbore. Non-intrusive downhole measurements may be taken from
numerous locations in the downhole environment. Very accurate
measurements can be taken because of optimal transducer placement
outside the wellbore Very long service life of transducers because
power is supplied by a wellbore device capable of supplying
transducer excitation. Direction formation properties may be
measured by comparing the many available downhole measurements.
[0028] The particulate material utilized in accordance with the
present invention to carry sensors 410 into formations 420, 425,
and 430 is preferably graded sand which is sized based on a
knowledge of the size of the formation fines and sand in an
unconsolidated subterranean zone to prevent the formation fines and
sand from passing through the gravel pack. The graded sand
generally has a particle size in the range of from about 10 to
about 70 mesh, U.S. Sieve Series. Preferred sand particle size
distribution ranges are one or more of 10-20 mesh, 20-40 mesh,
40-60 mesh or 50-70 mesh, depending on the particle size and
distribution of the formation fines and sand to be screened out by
the graded sand.
[0029] The particulate material carrier liquid utilized, which can
also be used to fracture the unconsolidated subterranean zone if
desired, can be any of the various viscous carrier liquids or
fracturing fluids utilized heretofore including gelled water, oil
base liquids, foams or emulsions. The foams utilized have generally
been comprised of water based liquids containing one or more
foaming agents famed with a gas such as nitrogen. The emulsions
have been formed with two or more immiscible liquids. A
particularly useful emulsion is comprised of a water-based liquid
and a liquified normally gaseous fluid such as carbon dioxide. Upon
pressure release, the liquified gaseous fluid vaporizes and rapidly
flows out of the formation.
[0030] The most common carrier liquid/fracturing fluid utilized
heretofore which is also preferred for use in accordance with this
invention is comprised of an aqueous liquid such as fresh water or
salt water combined with a gelling agent for increasing the
viscosity of the liquid. The increased viscosity reduces fluid loss
and allows the carrier liquid to transport significant
concentrations of particulate material into the subterranean zone
to be completed.
[0031] A variety of gelling agents have been utilized including
hydratable polymers which contain one or more functional groups
such as hydroxyl, cis-hydoxyl, carboxyl, sulfate, sulfonate, amino
or amide. Particularly useful polymers are polysaccharides and
derivatives thereof which contain one or more of the
monosaccharides units galactose, mannose, glucoside, glucose,
xylose, arabinose, fructose, glucuronic acid or pyranosyl sulfate.
Various natural hydratable polymers contain the foregoing
functional groups and units including guar gum and derivatives
thereof, cellulose and derivatives thereof, and the like.
Hydratable synthetic polymers and co-polymers which contain the
above mentioned functional groups can also be utilized including
polyacrylate, polymeythlacrylate, polycrylamide, and the like.
[0032] Particularly preferred hydratable polymers, which yield high
viscosities upon hydration at relatively low concentrations, are
guar gum and guar derivatives such as hydroxypropylguar and
carboxymethylguar and cellulose derivatives such as
hydroxyethylcellulose, carboxymethylcellulose and the like.
[0033] The viscosities of aqueous polymer solutions of the types
described above can be increased by combining cross-linking agents
with the polymer solutions. Examples of cross-linking agents which
can be utilized are multivalent metal salts or compounds which are
capable of releasing such metal ions in an aqueous solution.
[0034] The above described gelled or gelled and cross-linked
carrier liquids/fracturing fluids can also include gel breakers
such as those of the enzyme type, the oxidizing type or the acid
buffer type which are well known to those skilled in the art. The
gel breakers cause the viscous carrier liquids/fracturing fluids to
revert to thin fluids that can be produced back to the surface
after they have been utilized.
[0035] The creation of one or more fractures in the unconsolidated
subterranean zone to be completed in order to stimulate the
production of hydrocarbons therefrom is well known to those skilled
in the art. The hydraulic fracturing process generally involves
pumping a viscous liquid containing suspended particulate material
into the formation or zone at a rate and pressure whereby fractures
are created therein. The continued pumping of the fracturing fluid
extends the fractures in the zone and carries the particulate
material into the fractures. Upon the reduction of the flow of the
fracturing fluid and the reduction of pressure exerted on the zone,
the particulate material is deposited in the fractures and the
fractures are prevented from closing by the presence of the
particulate material therein.
[0036] As mentioned, the subterranean zone to be completed can be
fractured prior to or during the injection of the particulate
material into the zone, i.e., the pumping of the carrier liquid
containing the particulate material through the slotted liner into
the zone. Upon the creation of one or more fractures, the
particulate material can be pumped into the fractures as well as
into the perforations and into the annuli between the sand screen
and shroud and between the shroud and the well bore.
[0037] In another presently preferred embodiment, sensors are
placed into a formation by drilling laterally away from a borehole.
FIG. 5 shows a flow chart of this method. FIGS. 6A-6C depict an
instrument suitable for performing this method. As used herein,
drilling laterally away from a borehole means in a direction
greater than zero degrees away from the general longitudinal (as
opposed to radial) direction of the borehole at that particular
location and, thus, can include drilling up or down away from the
borehole when the longitudinal direction of the borehole is
horizontal with respect to the earth's surface. Furthermore, there
is no requirement that drilling laterally away from a borehole mean
normal or perpendicular to the surface of the wellbore.
[0038] A borehole 602 is drilled using conventional methods well
known to one skilled in the art (step 510). A sensor placement
device 600 is then placed into the borehole 602 (step 515). Sensor
placement device 600 consists of tubing 650, a fluid diverter 634,
a control line 692, outer tubing 636, pistons 630 and 631, a sensor
622, a nozzle 632, a deflector 610, and a wire 624. Tubing 650 is
lowered into the borehole 602 from the earth's surface 693. Tubing
650 may be coiled tubing of a type well known to one skilled in the
art.
[0039] Attached to tubing 650 are fluid diverters 634. An opening
652 allows fluid to flow from tubing 650 through fluid diverters
634 and into control line 692 which is attached to fluid diverters
634 by Swagelok fittings. At the end of control tube 692 are two
pistons 630 and 631. Pistons 630 and 631 provide an offset area for
pressure to work against so the outer tube 636 (also called a
cylinder) will stroke downward upon application of pressure. This
is the placement means for sensor 622. Pistons 630 and 631 are
rigidly attached to fluid or flow diverters 634. In one embodiment,
pistons 630 and 631 may be a smaller size of control line than
outer tubing 636. Although described herein with reference to two
pistons, multiple pistons may be used as well and may be deployed
in a variety of directions, such as, for example, up, down, or at
an angle, without departing from the scope and spirit of the
present invention.
[0040] Overlying control line 692 is outer tubing 636. Outer tubing
636 is pushed onto pistons 630 and 631 and remains in a retracted
position until pressure is applied. Upon application of pressure,
nozzle 632 provides a jetting action for the fluid, which
effectively cuts through the formation. As nozzle 632 erodes the
formation material, the outer tubing 636 is allowed to move
downwards. Sensor 622 is attached to the inside of outer tubing 636
by a threaded carrier sub that has an open ID to allow fluid to
bypass to nozzle 632. Outer tube 636 has a nozzle 632 at one end.
Sensor 622 is attached to outer tubing 636, either by integration
into the housing wall or surface mounting, and is connected to wire
624 that connects sensor 622 to a surface electronics 690. Surface
electronics 690 may include a recorder to record the data received
from sensor 622 for later processing possibly at a remote site and
may also include processing equipment to process the data received
from sensor 622 as it is received. Furthermore, surface electronics
690 may be attached to display devices such as a cathode ray tube
(CRT) or similar computer monitor device and/or to a printer.
[0041] After sensor placement device 600 has been placed down hole
(step 515), the fluid pressure inside tubing 650 is increased (step
520). The pressure may be increase by, for example, a pump on the
surface is connected to the coiled tubing 650, which provides the
high pressure source required to operate the drilling operation or
by a subsurface powered pump. The increased fluid pressure causes
fluid to flow through opening 652 into fluid diverter 634 which
diverts fluid into control line 692 causing sensor pods 680 to
extend (step 525). Water may be used as the working fluid unless
this will adversely affect the formation sandface. In such event, a
conventional mud may be used. The fluid may also be a treated
liquid comparable with the reservoir to minimize formation damage
and may possibly be enhanced with friction reducing polymers and
abrasives to enhance jet drilling efficiency. The fluid flows from
control line 692 into outer tubing 636. The fluid exits outer
tubing 636 through nozzle 632. The fluid exiting through nozzle 632
cuts through the surrounding rock, thus drilling the sensor pod 680
into place as housing 636 continues to extend exerting pressure on
sensor pod 680 (step 530). Deflector 610 causes sensor pod 680 to
be deflected outward into the formation 604.
[0042] The surface 612 of deflector 610 can have an angular 611
displacement away from the surface of tubing 650 of just greater
than zero degrees to almost 90 degrees depending on the direction
an operator wishes to place sensor pod 680. The greater the angular
611 displacement, the more sensor pod 680 will be deflected away
from tubing 650 such that an angular 611 displacement of almost 90
degrees will result in the sensor pod being deflected in a
direction almost perpendicular to the surface of tubing 650.
Deflector 610 may be constructed from any suitably hard material
that will resist erosion. For example, alloy stainless steel is an
appropriate and suitable material from which to construct deflector
610. Typically, deflector 610 is welded to the base pipe and
deflector 610 has a port drilled through it to allow fluid
passage.
[0043] Once sensor pod 680 has been drilled into the formation 604,
control line 692 may be retracted out leaving sensor pod 680 in the
formation (step 535). By leaving control line 692 in place rather
than removing it after sensor placement, wire 624 may be better
protected. Sensor 622 remains connected to surface electronics 690
via wire 624. Wire 624 can be an electric wire capable of carrying
electronic signals or it can be a fiber optic cable.
[0044] It should be noted that sensor 622 may be recalibrated after
placement of sensor 622 downhole in the formation. Such calibration
may be accomplished, for example, by means of transmissions via
wire 624 or may be through radio and/or acoustic signals.
[0045] To aid in understanding the present invention, refer to the
following analogy. Consider a garden hose with a nozzle attached to
the end. With the end of the nozzle pushed into the ground,
increase the water pressure in the garden hose. The water exiting
the nozzle provides an effective drilling tool that allows the hose
to be pushed into the ground. This is the principle behind the
present invention. The outer tubing will stroke downwards as the
formation material is removed. The wire attached to the sensor must
have enough length to accommodate the stoke length of the cylinder.
The wire may feed through the deflector and continue up the outside
of the coiled tubing. This may be useful if the coiled tubing is
removed after sensor placement. Otherwise as discussed above, the
wire will remain inside the coiled tubing where it is better
protected.
[0046] Although the present invention has been described primarily
with reference to interrogating the sensors with a wireline tool,
other methods of interrogating the sensor may be utilized as well
without departing from the scope and spirit of the present
invention. For example, the sensors could be interrogated by
something built into the completion or by a reflected signal that
could power up and interrogate the sensor or sensors.
[0047] The description of the present invention has been presented
for purposes of illustration and description, but is not intended
to be exhaustive or limited to the invention in the form disclosed.
Many modifications and variations will be apparent to those of
ordinary skill in the art. The embodiment was chosen and described
in order to best explain the principles of the invention, the
practical application, and to enable others of ordinary skill in
the art to understand the invention for various embodiments with
various modifications as are suited to the particular use
contemplated.
* * * * *