Note: Descriptions are shown in the official language in which they were submitted.
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DEVICES AND METHODS FOR GENERATING RADIALLY
PROPOGATING ULTRASONIC WAVES AND THEIR USE
FIELD
[0001] The present invention relates generally to sonic devices, and
particularly to
ultrasonic devices and related methods and their uses.
BACKGROUND
[0002] Sonic devices such as ultrasonic devices have applications in
various fields
and industries. For example, ultrasonic devices have been used in oil
extraction
processes. A sonotrode may be placed in a production well penetrating an oil
reservoir
to generate ultrasonic waves for assisting oil production.
[0003] Oil recovery efficiency from subterranean reservoirs containing
viscous
hydrocarbons may be improved or enhanced with the Injection of sound waves or
acoustic energy, such as to heat and reduce the viscosity of oil, increase the
permeability of the reservoir formation, and generally induce migration of oil
in the
formation into the well bore. Enhanced oil recovery (EOR) techniques also
include
injection of heat energy, such as using steam or heated fluid, or a chemical
agent,
such as solvent, surfactant, diluting liquid, detergent, wetting agent,
emulsifier,
foaming agent, or dispersant, into the reservoir. Different techniques may be
combined
to achieve better results.
[0004] An example of an acoustic device used for increasing oil production
through
vertical wells is disclosed in US 7,063,144 to Abramov et al., entitled
"Acoustic Well
Recovery Method and Device" and issued June 20, 2006.
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[0005] EOR through horizontal wells presents unique challenges, as compared
to
recovery through vertical wells, but also presents opportunities for
innovative
techniques to achieve improved results or efficiency. Improvement to recovery
techniques through vertical wells is also desired.
SUMMARY
[0006] It has been surprisingly discovered that an acoustic waveguide
having a
resonance cavity with conoidal end portions can provide more efficient radial
dispersion of acoustic energy and thus improved performance, such as when used
in
fluid production from horizontal wells, or from vertical or directional wells.
[0007] Thus, in one aspect, the present disclosure relates to an acoustic
waveguide
comprising a body defining a resonance chamber, the body comprising a tubular
section defining a cylindrical central portion of the chamber along a
longitudinal axis;
and first and second end sections extending from opposite ends of the tubular
section,
each one of the end sections comprising an end wall tapering away from the
tubular
section and towards the longitudinal axis thus defining a conoidal end portion
of the
chamber. The end wall and the longitudinal axis may be at an angle of about 45
to
about 70 degrees, such as about 50 to about 55 degrees. The resonance chamber
may contain a rarefied gas. The resonance chamber may be sized and shaped to
exhibit a resonant frequency in the range of 10 to 50 kHz. The waveguide may
be
configured and sized to optimize radial dispersion of sonic energy through the
waveguide.
[0008] In another aspect, there is provided a sonic device comprising a
waveguide
disclosed herein, and an acoustic transducer coupled to at least one of the
end
sections of the waveguide. The transducer may be a magnetostrictive or
piezoelectric
transducer. The sonic device may further comprise a housing, wherein the
transducer
is mounted in the housing and is immersed in a cooling fluid. The sonic device
may
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further comprise a pressure compensator in the housing. The transducer may
have a
working frequency, and the waveguide may be configured such that a resonant
frequency of the sonic device matches the working frequency of the transducer.
The
resonant frequency may be a resonant frequency of longitudinal oscillation.
The
resonant frequency of the sonic device may differ from the working frequency
of the
transducer by less than 10% of the working frequency. The transducer may
comprise
a magnetostrictive transducer. The magnetostrictive transducer may have first
and
second elongated openings, aligned and spaced apart in a longitudinal
direction, and
wherein a coil passes through each one of the first and second openings. Each
one of
the end sections of the waveguide may be coupled to an acoustic transducer.
[0009] A further aspect relates to a method comprising generating a
radially
propagating acoustic wave with a sonic device as disclosed herein, which is
positioned
in a well penetrating a hydrocarbon reservoir. The method may further comprise
injecting a chemical agent into the well. The sonic device may be connected to
an
injector for injecting the chemical agent, and the sonic device and injector
may be
moved to and fro in the well in synchronization. The sonic device and injector
may be
connected to a cable, such as a cable hose. The cable hose may comprise a
fluid
conduit for supplying the chemical agent to the injector and a conducting wire
for
transmitting power to the sonic device. The cable hose may further comprise a
signal
wire for transmitting a signal therethrough. The well may be a horizontal
well, a vertical
well, or a directional well.
[0010] In another aspect, there is provided a downhole tool assembly
comprising a
sonic device disclosed herein; an injector for injecting a chemical agent into
a
perforated wellbore portion of a well penetrating a hydrocarbon reservoir; and
a
movable cable hose connected to the injector and the sonic device for moving
the
injector and the sonic device to and fro in synchronization, the cable hose
comprising
a conducting wire for supplying power to the sonic device and having a conduit
for
supplying the chemical agent to the injector. The cable hose may further
comprise a
signal wire for transmitting a signal therethrough.
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[0011] Other aspects, features, and embodiments of the present disclosure
will
become apparent to those of ordinary skill in the art upon review of the
following
description of specific embodiments in conjunction with the accompanying
figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] In the figures, which illustrate, by way of example only,
embodiments of the
present disclosure:
[0013] FIG. 1A is a schematic cross-sectional view of an acoustic
waveguide;
[0014] FIG. 1B is an axial cross-sectional view of the acoustic waveguide
of FIG.
1A, taken along line 1B-1B;
[0015] FIG. 2 is a schematic cross-sectional view of a sonic device
including the
acoustic waveguide of FIG. lA coupled to acoustic transducers;
[0016] FIG. 3A is a cross-sectional view of the sonic device with
additional
components;
[0017] FIGS. 3B and 3C are axial cross-section view of the sonic device of
FIG. 3A,
taken along lines 3A-3A and 3B-3B respectively;
[0018] FIG. 4 is a schematic cross-sectional view of a base body for a
magnetostrictive transducer;
[0019] FIG. 5A is a schematic cross-sectional elevation view of a tool
assembly in a
horizontal well penetrating a reservoir formation;
[0020] FIG. 56 is a cross-sectional view of the cable hose in the tool
assembly of
FIG. 5A;
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[0021] FIG. 5C is a schematic cross-sectional view of an end section of the
sonotrode in the tool assembly of FIG. 5A;
[0022] FIG. 6 is a schematic cross-sectional elevation view of another tool
assembly in a vertical well penetrating a reservoir formation; and
[0023] FIG. 7 is a graph showing calculation results of displacement
distribution in
a sample sonic device.
DETAILED DESCRIPTION
[0024] An embodiment of the present disclosure relates to an acoustic
waveguide
100 as illustrated in FIGS. 1A and 1B.
[0025] Waveguide 100 has a generally cylindrical body 101, which defines a
resonance chamber 102. Body 101 includes a tubular section 104 and two end
sections 106 extending from opposite ends of tubular section 104. Tubular
section 104
defines a cylindrical central portion of chamber 102. Cylindrical body 101,
tubular
section 104, and the cylindrical central portion of chamber 102 extend along a
central
axis 108. Each end section 106 has a tapered wall 110, which tapers away from
tubular section 104 and towards central axis 108, thus defining a conoidal end
portion
of chamber 102.
[0026] Chamber 102 may be filled with a rarefied gas. The gas may be air at
a
reduced pressure. As can be appreciated, sound wave propagation requires a
medium, and cannot occur in complete vacuum. Sound wave propagation in a dense
medium can result in significant energy loss. Therefore, a resonance chamber
filled
with a rarefied gas, or partially evacuated, has an increased efficiency, as
compared to
a resonance chamber filled with atmospheric air, since potential loss of
acoustic
energy in the chamber are reduced or minimized. Potential energy loss may be
due to
transfer of acoustic energy into the chamber and conversion of acoustic energy
to
another form of energy such as heat or vibration inside the chamber.
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[0027] The angle (0) between central axis 108 and each end wall 110 may
vary
from about 45 to about 70 . As will be further discussed below, in some
embodiments, 0 may be about 50 to about 55 . The angle 0 may be selected to
optimize operation performance as will be further discussed below. As can be
appreciated, a change in the angle 8 can result in a change in oscillation
amplitude in
different directions and in own oscillation frequencies. See below for test
results of the
effects of changing 0. For example, in some configurations, a maximum
amplitude
may be obtained when e is between 50 to 55 .
[0028] The dimensions of body 101, tubular section 104 and end sections 106
are
selected to provide a selected or desired resonance frequency (fr). For
example, when
waveguide 100 is to be coupled to an acoustic transducer with a working
frequency fw
(see below), the resonance frequency fr may be selected to match the working
frequency f,. For the purpose of this disclosure, I`, is considered to match
f,,õ if fr = fi,õ or
if (f,- -f )1f, < 0.1. The resonance frequency normally refers to a
longitudinal oscillation
frequency (that is, the resonant vibration frequency in the axial direction).
For example,
tubular section 104 may have a length of about 258 mm and an outer diameter of
about 44 mm. Different lengths and diameters may also be suitable or selected
in
various embodiments and applications. The thickness of tubular section 104 of
body
101 may be about 6 mm. This thickness may be selected so that it is
sufficiently thin to
efficiently transmit acoustic energy with limited or minimized energy loss,
and it is
sufficiently thick to have the required physical strength for normal
operation.
[0029] Body 101 may be formed of any suitable material for forming acoustic
waveguides, particularly waveguides for providing ultrasonic resonance. For
example,
body 101 may be formed of a suitable metal or alloy. In some embodiments,
titan may
be used to form body 101. In some embodiments, stainless steel may be used to
form
body 101.
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[0030] Body 101 may optionally include channels or conduits (not shown in
FIG. 1A,
but see FIG. 2 for an example) for various purposes, such as for inserting an
energy
source or another component into body 101.
[0031] Chamber 102 may be filled with a rarefied gas. The rarefied gas may
include
air at a reduced pressure. The pressure may be close to zero to provide
optimal
efficiency. In some cases, the pressure may be reduced to as low as is
practically
possible.
[0032] In use, waveguide 100 may be coupled to an acoustic transducer that
generates mainly longitudinal sound vibrations to efficiently produce radially
propagating sound waves.
[0033] An example of such use is schematically illustrated in FIG. 2. As
depicted in
FIG. 2, a sonic device 200, which may be referred to as a sonotrode, includes
waveguide 100 and two acoustic transducers 202 coupled to opposite axial ends
of
waveguide 100 respectively.
[0034] Each transducer 202 may be constructed according to a suitable known
acoustic transducer technique. Example conventional techniques for
constructing
suitable acoustic transducers include those disclosed in, e.g., 0. V. Abramov,
"High-
Intensity Ultrasonics: Theory and Industrial Applications," CRC Press, 1999.
[0035] In some embodiments, transducers 202 may include an electric powered
magnetostrictive transducer, and may be made of permendur. In some
embodiments,
other suitable materials with magnetostrictive or piezoelectric properties may
be used.
As is known to those skilled in the art, an electrical coil may be wound
around a
transducer 202 to induce an alternating magnetic field in the transducer body
when an
alternating electrical current is applied through the coil. The varying
magnetic field
causes the transducer body to expand or contract, resulting in a corresponding
oscillating displacement of an adjacent object abutting the transducer, such
as
waveguide 100 shown in FIG. 2. When the oscillation frequency is suitably
selected,
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ultrasonic waves are generated and transmitted outward into the surroundings.
Sonotrodes 200 may be configured to maximize radial dispersion of ultrasonic
waves.
[0036] In an embodiment, the dimensions of waveguide 100 and transducers
202
may be as listed in Table I.
TABLE I. Dimensions of Sample Sonic Device illustrated in FIG. 2
Length Diameter Cone
(mm) (mm) Angle 8
Waveguide Body 405 44
Cylindrical Portion 258 32
End Portion 73.5 44 55
Transducer Body 134
[0037] In this example, transducer 202 has a working (operating) frequency
of
18.49 kHz and the entire device (a waveguide and two transducers) has a
resonant
frequency of 18.55 kHz.
[0038] As will be appreciated and understood by those skilled in the art,
to
implement device 200 in a practical application, additional features and
components
will be required, for example, to provide power and control of the device, and
to
interconnect different components in the device and connect the device to
other tools
or equipment used in a particular application. Additional components may also
be
necessary or optional to provide other functionalities or improved
performance, some
of which will be illustrated below.
[0039] In particular, for simplification, the windings for providing a
varying magnetic
field are not shown in some figures as they are not needed to show the
modifications
under discussion, but it should be understood that appropriate windings will
be
required in some practical implementations.
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[0040] An example sonic device 300 is illustrated in FIG. 3. In this
embodiment, the
acoustic transducer may include a transducer body 204 enclosed in a housing
302
filled with a cooling liquid 304, such as oil.
[0041] An electrical conducting wire may be wound about each transducer
body
204 and connected to a power source for generating a varying magnetic field in
the
transducer 300. The transducer body 204 may have an opening 206, as depicted
in
FIG. 3A (also see FIG. 2), to allow the conducting wire to be wound through
opening
206 around each of the top section and the bottom section of body 204.
[0042] Opening 206 may be selected so that necessary windings can be
provided
therethrough. The number of coil windings can affect the efficiency of the
device. The
winding may be selected to match the impedance, and will depend on the
material
characteristics of the material used to form the transducer. It may be
desirable to
operate in or near the saturation zone of the material. The width of opening
206 is
selected depending on the diameter of the winding wire or cable. That is, the
winding
wire or cable will need to be able to fit within the opening. A winding cable
may be
chosen based on its characteristics, taking into account of the desired
current that will
pass through the cable during operation.
[0043] As depicted in FIG. 3A, a winding wire (or cable) 306 may be used to
form
windings on both transducers 302 and may pass through waveguide 100. Winding
wire 306 is connected to a power source or signal source (not shown) for
supplying the
power or signal required for operation. To allow winding wire 306 to pass
through
waveguide 100, a channel 308 may be provided. Channel 308 may be filled with a
fluid
312, which can be the same as fluid 304.
[0044] Device 300 may have a working frequency range from about 10-50 kHz,
such as about 20 kHz.
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[0045] In alternative embodiments, the transducer body may have two winding
openings as illustrated in FIG. 4. The transducer 400 depicted in FIG. 4 has a
transducer body 402 with two elongated openings 404 and 406. Openings 404 and
406 are aligned and spaced apart, such as by a distance of about one to two
times of
the distance between each opening to the side edge of the device. Each opening
404
and 406 has a generally rectangular profile, with length and height selected
to
accommodate the winding wires to be passed therethrough, as discussed above.
[0046] Sonic device 200 or 300 may be used in an oil or gas extraction
process,
such as illustrated in FIG. 5A.
[0047] As depicted in FIG. 5A, a horizontal well 520 penetrates a reservoir
530
containing hydrocarbons, which may be present in the form of oil or gas.
Horizontal
well 520 is completed with a cement casing 522 around the perimeter of the
wellbore,
as can be understood by those skilled in the art. Casing 522 at a horizontal
section of
well 520 has perforations extending through cement casing 522 to provide fluid
pathways and fluid communication between well 520 and reservoir 530. As is
typical, a
string of tubing 524 extends into well 520 from surface 532. Tubing 524 may be
used
to transport or lift fluids produced from reservoir 530 to surface 532, and
may be
connected to a pumping unit, such as pumping unit 533 at surface 532, or
another
pump disposed downhole (not shown). For example, a submersible electric
pump (SEP) may be used downhole to drive fluid flow in tubing 524.
[0048] It should be noted that while horizontal wells are depicted in HG.
5A, and
the related description refers to horizontal wells for simplicity and brevity,
the same or
similar tools or techniques may be used in vertical wells or directional wells
as well.
[0049] It is noted that other necessary or optional components or well
completion
parts or tools, such as liners, packers, hangers, working strings, tubing,
sensors,
cables, joints, pumps, wire or cable racks, or the like, may also be provided,
and
installed, as are known to those skilled in the art. The sensors may include,
for
example, manometers, and thermometers or thermocouples, or the like. However,
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exact structures and details of well 520, casing 522 including its
perforations, tubing
524, any pumping unit including pumping unit 533, the other necessary and
optional
components, parts, or tools, and the associated equipment, are not critical to
the
present disclosure and have been generally described only to the extent
necessary to
illustrate this embodiment of the present disclosure. The nature and operation
of such
components, parts, tools, and equipment are known to those skilled in the art,
and can
be selected and implemented by those skilled in the art as suitable in a given
application, in combination with the components and downhole tools expressly
described in this disclosure.
[0050] As used herein, a horizontal well refers to any well that has an
extended
lateral wellbore section that extends generally substantially in the
horizontal direction.
A section of a horizontal well may extend from the surface 532 generally
vertically (as
illustrated in FIG. 5A), or at an inclined angle (not shown), down to a
selected level into
the reservoir formation. It is not necessary that the entire wellbore of a
horizontal well
is leveled in the horizontal direction.
[0051] As used herein, the term "surface", in expressions such as "the
surface", "at
surface", "from surface", or the like, should be understood to refer to the
earth surface,
or generally any facilities or equipment located above or on the ground near
the top
end of horizontal well, unless the term is otherwise qualified or the context
makes it
clear that the term refers to a particular surface other than the earth
surface.
[0052] FIG. 5A also depicts a tool assembly 5100, which includes a cable
hose
5110, a jet pump 5120, a hydraulic giant 5130, an acoustic tool unit, which
includes
one or more of sonotrodes 5140 and an electrohydraulic shock wave tool 5150,
and
flexible connectors 5160 for connecting various components or units in the
tool
assembly. The combination of hydraulic giant 5130, sonotrodes 5140, shock wave
tool
5150, and flexible connectors 5160 may be considered as a unit collectively
referred to
as a downhole tool or a downhole tool unit.
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[0053] It should be noted that, while various tool components are shown and
discussed herein, in some embodiments it is not necessary to use all of the
components described in the same tool assembly. For example, in a simple
application, an ultrasonic downhole tool containing a sonotrode as described
herein
may be lowered into a well, which can be a vertical well, using a cable, and
the tool
may be powered from the surface using an ultrasonic generator. Other
components of
in tool assembly 5100 to be described below can be optionally selected and
used.
[0054] Cable hose 5110 is used primarily to transport a chemical agent into
the
perforated wellbore section of well 520. However, as will be further described
and will
become apparent below, cable hose 5110 is also configured and adapted to
provide
additional functionalities, including transmission of electrical power to
other downhole
tools such as sonotrodes 5140 and shock wave tool 5150, and for running other
downhole tools in the assembly and actuating continuous movement of such
tools, so
that synchronized movement of such tools with the injector of the chemical
agent can
be conveniently effected and controlled. Cable hose 5110 may also be used to
flow
other fluids downhole. For example, cable hose 5110 may be used to transport a
cleaning fluid downhole to wash and clean a perforated portion of well 520,
either
before or after chemical treatment, as will be further described below.
[0055] Cable hose 5110 is flexible and may be formed with an armored
plastic
cable body. FIG. 5B depicts a transverse cross-sectional view of cable hose
5110. As
illustrated in FIG. 5B, cable hose 5110 includes a plastic core 5111 defining
a fluid
conduit 5112. A plurality of wires, including armor wires 5113, power wires
5114, and
signal wires 5115, are embedded and extend in plastic core 5111. Armor wires
5113
are used to provide mechanical strength and may be made of steel such as a
suitable
stainless steel.
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[0056] It is noted that in different embodiments, a downhole tool or tool
assembly
may be lowered into a well (horizontal, vertical or directional) using a
conventional
string or cable used to run downhole tools into the well, as known to those
skilled in
the art.
[0057] Armor wires 5113 may also be made of another material with suitable
mechanical properties, and do not need to be electrically conductive.
[0058] Power wires 5114 are used to transmit electrical power. Signal wires
5115
are used to transmit electric or electronic signal. Both power wires 5114 and
signal
wires 5115 are made of a suitable electrically conductive material, such as
copper or
the like. Power wires 5114 and signal wires 5115 may be made of the same
material
but their gauge size may be different, as a power wire may have a larger gauge
size
than a signal wire. The gauge size of a power wire may also vary depending on
the
power required to power a particular downhole tool or equipment. For example,
in a
particular embodiment, a suitable copper power wire may have a diameter of
about 1.5
mm, and a copper signal wire may have a diameter of 0.5 mm or less. The power
rating for power wires 5114 may be up to 5 kW. While two power wires and four
signal
wires are shown in FIG. 5B, it should be understood that the numbers of power
wires
5114 and signal wires 5115 may vary in different applications, and may be
selected
depending on the number downhole tool units to be powered and the number of
signals to be transmitted from downhole to surface. Signal wires 5115 may be
used to
transmit data signals from a downhole tool or equipment such as a sensor to a
surface
apparatus or unit, and transmit control signals from a surface apparatus or
unit to a
downhole tool or equipment, as needed.
[0059] The diameter of cable hose 5110 may be selected such that the
diameter of
fluid conduit 5112 is optimized for a given wellbore size and the downhole
room
available for cable hose 5110. Generally, a larger diameter for fluid conduit
5112 may
be desirable to achieve a higher flow rate under the same fluid pressure.
However, the
size of cable hose 5110 and hence the size of fluid conduit 5112 may be
limited by
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available space within the wellbore. In a particular embodiment, the diameter
of fluid
conduit 5112 may be about 15 mm. The diameter of cable hose 5110 may be
selected
to ensure that cable hose 5110 is of sufficient mechanical strength for
performing the
desired functions and have sufficient durability. In an embodiment, the outer
diameter
of cable hose 5110 may be 44 mm. The inner surface fluid conduit 5112 may be
formed of a material chemically resistant to any chemical agent to be
transported
through conduit 5112. For example, if an acidic fluid is to be transported
through
conduit 5112, the inner surface of conduit 5112 may need to be acid-resistant.
This
may be achieved by selecting a suitable acid-resistant core material, or by
coating an
acid-resistant material on the inner wall of conduit 5112. A suitable material
for the
core of cable hose 5110 may be a polymer.
[0060] As can be seen in FIG. 5A, cable hose 5110 extends from surface 532,
and
the surface end of cable hose 5110 is connected to a source 534 of a chemical
agent
for supplying the chemical agent into conduit 5112 of cable hose 5110. Cable
hose
5110 is also wound onto a cable drum 535 on a cable truck 536. Source 534 may
be
provided in any suitable manner or form, such as by way of a stationary or
movable
tank, or a truck carrying a fluid container. Cable hose 5110 is deployed and
actuated
during operation by turning cable drum 535 on truck 536. Conveniently, a
geophysical
truck may be adapted to carry and operate cable hose 5110. A specially
designed and
configured truck may also be used.
[0061] Cable hose 5110 may be otherwise deployed and actuated without truck
536, such as by using a suitable cable winding device with a motorized spindle
or
winding wheel (not shown). However, as can be appreciated by persons skilled
in the
art, using a truck carrying a cable drum can provide certain benefits and
advantages.
For example, the cable truck can be easily moved about either on site, or from
site to
site, without having to load and unload cable hose 5110 for relocation. The
length of
cable hose 5110 may be quite long, such as up to hundreds meters, or more than
2-3
kilometers, depending on the lengths of the wells in which cable hose 5110 is
to be
used. For this purpose, armored cable hose 5110 is beneficial as armor wires
5113
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can provide additional stretching, bending (breaking) and torsional strength
and
stiffness.
[0062] Conveniently, geophysical signals from geophysical sensors (not
shown)
deployed downhole in well 520 may be transmitted to data analysis units (not
shown)
on geophysical truck 536 through one or more signal wires 5115.
[0063] While specific embodiments of cable hose 5110 are described above,
it
should be noted that cable hose 5110 may be modified, such as by using
different
materials and constructions, but still provides the same or similar
functionalities as
described above. For example, the cable body may be formed of a material other
than
a polymer plastic, as long as the material can provide sufficient physical
strength and
flexibility and chemical stability for the intended use. The wires may also be
formed of
different materials for conducting electricity.
[0064] The downhole end of cable hose 5110 extends to a downhole location
near
the perforated section of well 520, and passes through a junction at which a
jet pump
5120 is located.
[0065] Jet pump 5120 may be any suitable conventional jet pump that has
been
modified as described below to allow cable hose 5110 to pass through jet pump
5120
and form a pressure seal around cable hose 5110 in jet pump 5120.
[0066] Other types of pumps may also be used. For example, in vertical
wells
conventional jet pumps can be used during treatment or after the treatment.
When a
jet pump is used, the jet pump housing may be configured to allow the downhole
tool
assembly 5100 to pass through it. In some cases, downhole tool assembly 5100
may
be used without the use of any jet pump.
[0067] Below the junction where jet pump 5120 is located, a packer (not
shown) is
set to isolate the sections of well 520 above and below the packer and jet
pump 5120,
or in other words, to isolate tubing 524 from the section of well 520 above
the packer.
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[0068] Jet pump 5120 is configured to allow cable hose 5110 to pass
therethrough
and provide a pressure seal (not shown) around cable hose 5110 in jet pump
5120.
The seal can closely and tightly engage the outside perimeter of cable hose
5110 to
form a tight fluid seal, yet still allowing cable hose 5110 to slidably move
back and
forth during operation. The seal prevents fluid communication between tubing
524
above jet pump 5120 and the perforated wellbore section of well 520, so that a
pressure differential can be established therebetween. In an embodiment, a
pressure
differential up to 400 atm may be created by jet pump 5120.
[0069] The downhole end of cable hose 5110 is connected and coupled to
hydraulic giant 5130, which has a nozzle head (not separately shown) in fluid
communication with conduit 5112 for injecting the chemical agent, or any other
fluid
flowing in conduit 5112, into reservoir 530 through the perforated section of
well 520.
In different embodiments, hydraulic giant 5130 may be replaced with another
type of
nozzle device for injecting fluid into the wellbore of well 520. In some
embodiments,
the nozzle of hydraulic giant 5130 may be oriented to inject the fluid at an
about 45
degree angle to the axial direction of well 520.
[0070] In different embodiments, hydraulic giant 5130 may be modified or
replaced
with any suitable device for injecting the chemical agent into the wellbore.
Such a
device may be broadly referred to as an injector (not an injection well) for
injecting the
chemical agent. The injector may include a nozzle, a tubing, or another fluid
device
(not separately shown) that can be conveniently coupled to the downhole end of
cable
hose 5110 for dispersing the chemical agent in a desired manner.
[0071] One or more sonotrodes 5140 may be connected by flexible connectors
5160 to the downhole end of cable hose 5110, in series. The power input of
each
sonotrode 5140 is connected directly or indirectly to a power wire 5114 of
cable hose
5110. To this end, a wire rack (not shown) may be provided near hydraulic
giant 5130,
for connecting with power wires 5114 and signal wires 5115. Lead wires (not
shown)
may be provided to connect input or output terminals in different downhole
tools or
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equipment to the wire rack for respective electrical connection with power
wires 5114
and signal wires 5115.
[0072] Sonic device 200 or 300 may be used as one or more of sonotrodes
5140.
Waveguide 100 may also be otherwise used in one or more of sonotrodes 5140.
The
windings in each sonotrode 5140 may be connected to a power source for
generating
a varying magnetic field in its transducer.
[0073] When a sonic device, such as device 300, is used in such an
embodiment, it
may be beneficial to provide a pressure compensator, as illustrated in FIG.
5C.
[0074] As depicted in FIG. 5C, a compensator 320 may be provided in housing
302, which includes a wall plate 322 that is slidably and sealingly movable in
the
housing bore. The wall plate 322 is biased against a spring 324 mounted on an
end
wall 326 of housing 302. Housing 302 also has openings 328 in the section
between
wall plate 322 and the housing end wall 326, to provide fluid communication
with the
surrounding area. The strength of spring 324 is selected to provide pressure
balance
between the pressure in the housing bore and the fluid pressure in the
surrounding
area. When the surrounding pressure is reduced, spring 324 may be compressed
by
wall plate 322 due to a higher pressure in cooling liquid 304. When the
surrounding
pressure is increased, the combined force by the surrounding pressure and
spring 324
pushes wall plate 322 to compress cooling liquid 304 thus increasing its
pressure.
Therefore, the pressures inside and outside housing 302 are balanced and
compensated. The pressure load on spring 324 may be up to about 2 to about 3
atm.
A minimum pressure of 2 to 3 atm may be maintained in housing 302 at all times
in
order to avoid cavitation inside the housing bore and prevent damage to wires
or other
components inside housing 302.
[0075] Conveniently, with waveguide 100, ultrasonic waves can be
transmitted into
the surroundings both axially and radially, and a sonotrode 5140 can be
configured to
optimize or maximize radial dispersion of ultrasonic waves.
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[0076] Waveguides 100 and transducers described herein may be used to
replace
waveguides and transducers in various conventional sonotrodes or acoustic
devices
known to persons skilled in the art, and the persons skilled in the art will
be able to
design and construct sonotrodes having the above discussed features and
properties.
For example, waveguides and transducers described herein may be used in
devices,
systems or processes disclosed in US 7,063,144 to Abramov et al., issued June
20,
2006, and US 7,059, 403 to Barrientos et al., issued June 13, 2006, the entire
contents
of each of which are incorporated herein by reference. Other example
sonotrodes and
operations thereof are described in US 7,059,413 to Abramov et al., issued
June 13,
2006, the entire contents of which are incorporated herein by reference.
Example
sonotrodes and associated surface equipment are also described in Abramova, A.
et
al., "Ultrasonic Technology for Enhanced Oil Recovery", Engineering, (2014),
6, pp.
177-184, the entire contents of which are incorporated herein by reference.
[0077] Test results have shown that a push-pull type sonotrode may be
beneficial
in some embodiments, where longitudinal oscillation in such a sonotrode is
converted
to radial oscillation, and sonic waves are emitted mainly radially, when the
radial and
longitudinal frequencies are matched with the specified margin. Radially
emitting sonic
waves can increase the efficiency of the sonotrodes.
[0078] In different embodiments, the operating frequency of the sonotrodes
may
vary. In a selected embodiment, the operating or resonance frequency may be
about
20 kHz. In some embodiments, the resonance frequency may be from about 10 to
about 50 kHz, or from about 15 to about 30 kHz. The input power for each
sonotrode
may be in the range of about 2 to about 3 kW, up to 10 kW, or higher. A
sonotrode
may have an output power of about 1.5 to about 5 kW.
[0079] When selecting the sonotrodes to be used and powering the
sonotrodes, it
may be born in mind that in some embodiments, the threshold energy intensity
for
achieving acoustic effects in subterranean oil and rocks (or oil sands) may be
0.8 to 1
W/cm2. Thus, the sonotrodes should be configured and arranged to achieve at
least
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such acoustic energy intensity in a volume of the reservoir formation near the
wellbore
such as within a meter from the wellbore casing.
[0080] When multiple acoustic tools such as sonotrodes 5140 or shock wave
tool
5150 are used in the same downhole tool unit, the acoustic tools may be
connected in
series with flexible connectors 5160, and by conductive wires or cables. Each
sonotrode 5140 in the same assembly or unit may have a distinct resonant
frequency,
and the resonant frequencies of different sonotrodes 5140 may differ from each
other
by at least about 1 kHz. As can be appreciated, ultrasonic waves with
different
frequencies may penetrate into a medium to different depths.
[0081] For use in horizontal wells, multiple sonotrodes 5140 may be evenly
spaced,
and may extend over substantially the entire perforated section of well 520.
The
number of sonotrodes 5140 and how they are placed may be determined based on a
number of factors including the length of the perforated wellbore section,
fluid flow
rate, operation efficiency, effectiveness, cost, and others.
[0082] The operation of sonotrodes 5140 may be controlled at surface, such
as at a
control station (not shown) located at surface. The control signal and
feedback may be
applied through power wires 5114 and signal wires 5115 of cable hose 5110. One
or
more power sources or generators (not shown) may be also be provided at
surface for
providing electrical power to sonotrodes 5140 through power wires 5114 of
cable hose
5110.
[0083] As used herein, unless otherwise specified, a radial direction
refers to a
direction that is perpendicular to the axial direction of the tool in
question, or to the
axial direction of the wellbore in which the tool is located. Typically, the
axial direction
of an elongated tool is aligned generally with the axial direction of the
wellbore.
[0084] The operation of each sonotrode 5140 may be controlled from surface
by
adjusting the power applied to the sonotrode and by actuating cable hose 5110
to
move sonotrodes 5140 back and forth in the axial direction. Each sonotrode is
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constructed and configured to generate and direct ultrasonic waves into a
volume of
the reservoir near well 520 or a vertical well through the perforated wellbore
portion of
well 520. To this end, sonotrodes 5140 are constructed and configured to
produce
sufficient radial oscillation.
[0085] Tool assembly 5100 may be guided by, or hang on, another working
string
(not shown) previously disposed downhole.
[0086] As now can be appreciated, for use in a horizontal well such as well
520,
downhole tools connected to the cable hose 5110, such as hydraulic giant 5130,
sonotrodes 5140, and shock wave tool 5150 should be sized so that they can be
conveniently inserted through tubing 524 and jet pump 5120. For this reason,
each of
the downhole tools may be sized to have a diameter similar to or smaller than
the
outer diameter of cable hose 5110. Since it may be desirable to provide larger
tools to
the extent possible under the wellbore constraints, these downhole tools may
have the
same outer diameter as cable hose 5110. For example, cable hose 5110,
sonotrodes
5140, and shock wave tool 5150 may each have an outer diameter of about 44 mm.
[0087] While not expressly shown, it should be understood that suitable
coupling,
connecting or engaging devices or components will be required to connect,
couple, or
engage different tools and devices to each other. For example, cable couplings
and
seal couplings may be provided to couple cable hose 5110 to hydraulic giant
5130. At
hydraulic giant 5130, cable hose 5110 may be coupled to a lug (not shown), and
may
be partially terminated or cut off, but power and signal wires 5114 and 5115
may
extend further downhole, to provide lead lines for connecting with other
downhole tools.
[0088] In some embodiments, and depending on the application, the acoustic
tool
unit connected to cable hose 5110 or a cable may include only one sonotrode.
In other
embodiments, the acoustic tool unit may include multiple sonotrodes. In some
embodiments, the acoustic tool unit may include multiple sonotrodes and
multiple
shock wave tools.
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[0089] During use, at a selected time during well completion, and prior to
normal
production, various necessary and optional equipment, devices and downhole
tools
may be lowered into the wellbore of horizontal wells 20 or vertical wells.
Fixtures such
as packers, a working string (not shown), a housing component or platform (not
shown)
for housing jet pump 5120, and tubing 524 may be installed or put in place in
casing
522. Jet pump 5120 is installed into place on tubing 524.
[0090] The downhole tool unit including inter alia, sonotrodes 5140, which
are
connected in series as shown in FIG. 5A for horizontal wells, is connected to
the
downhole end of cable hose 5110 or a cable, and may be run downhole using
cable
hose 5110 or cable through tubing 524 in casing 522, and then through jet pump
5120.
Cable hose 5110 may be lowered into well 520 by un-winding the drum 535 on
cable
truck 536.
[0091] As can be appreciated, while FIG. 5A depicts a horizontal well, a
similar
technique for installing a cable or downhole tool may be used to lower the
cable or
downhole tool into a horizontal well or a vertical well. Alternatively, the
downhole tool
may be attached to a well tubing, such as tubing 524, and lowered into the
well with
the well tubing.
[0092] The described sonotrodes may also be used during sonochemical
treatment
of vertical or horizontal wells. In this case, radiation of acoustical energy
is provided
during or after injection of chemicals into the treated zone. Conveniently,
the
simultaneous injection of chemical agent and ultrasonic energy into the
perforated
wellbore section and the volume of reservoir formation nearby, and the
synchronized
movement of the injection points, can provide synergistic effects, and improve
the
efficiency and effectiveness of the sonochemical treatment of the volume of
reservoir
formation near the perforated wellbore section and the perforated wellbore
section
itself.
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[0093] For example, and without being limited to any particularly theory,
it may be
expected that certain beneficial effects, such as fluid viscosity reduction
and mobility
increase, induced by ultrasonic stimulation, can assist fluid movement and
dispersion
of the chemical agent into the volume of the reservoir formation near the
perforated
wellbore section. However, such beneficial effects may quickly disappear or be
reduced after ultrasonic stimulation is terminated. For example, some effects
may be
reduced within tens of seconds or a few minutes after termination of
ultrasonic
stimulation. While the volume of reservoir formation is still stimulated by
sufficient
ultrasonic energy, the chemical agent may disperse deeper and faster into the
reservoir. In addition, some chemical or physical bonds between various
molecular
species or materials in the reservoir formation may be temporarily broken due
to the
ultrasonic stimulation, which may allow the chemical agent to react with such
molecular species or materials. Further, the amplitude of ultrasonic waves
propagating
in the reservoir formation may decay quickly and the effective region of
ultrasonic
stimulation tends to be limited to within a short radial distance from the
perforated
section of well 520. Injection of the chemical agent may result in increased
permeability in the volume. Consequently, the effectiveness and treatment
efficiency
may be improved. The synchronized movement of the chemical and ultrasonic
injection points may allow the wellbore and the reservoir formation to be more
evenly
and uniformly treated, and the above effects to be achieved. Tests have shown
that
continuous movement of the chemical and ultrasonic injection points in
horizontal wells
may be required to avoid clogging or blockage of the perforations in the
perforated
wellbore section, or may be required to achieve the above discussed beneficial
effects.
If the downhole tool unit were kept stationary during sonochemical treatment,
it might
be stuck in place after a period of operation, and it would be difficult to
move it again.
[0094] During the sonochemical treatment, hydraulic (fluid) shock waves may
be
generated using shock wave tool 5150, in addition to ultrasonic waves to
improve the
treatment performance. Hydraulic shock waves generated downhole typically can
penetrate further into reservoir 530, and may have a higher energy transfer
efficiency.
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Its application may be beneficial in some cases, but may also have negative
effects in
other cases as are known to those skilled in the art.
[0095] The skilled person will be able to determine in a particular case
whether it is
desirable to apply shock waves. For example, it may be more difficult to limit
the effect
of shock waves to within a confined zone. If there is a nearby formation
structure that
should not be subjected to shock wave stimulation, it may not be suitable to
apply
shock waves during the treatment.
[0096] The sonochemical or ultrasonic treatment of well 520 and reservoir
530 may
last any suitable period of time depending on the conditions of the particular
formation,
the nature of the treatment selected, and the chemical materials and sonic
energy
used. Depending on various factors, a sonochemical treatment may last about 30
to
about 60 min per meter for a vertical well, or about 2 to 15 min per meter for
a
horizontal well.
[0097] The sonochemical or ultrasonic treatment of well 520 and reservoir
530 may
be repeated over time when necessary or desired. For example, during normal
production of oil from well 520, production may be temporarily suspended, to
allow
well 520 and reservoir 530 to be subjected to a further period of sonochemical
or
ultrasonic treatment to improve fluid flow into well 520.
[0098] The frequency, power and duration of ultrasonic waves to be
generated may
be selected based on a number of factors known to those skilled in the art and
will not
be detailed herein. It should be noted that continuous ultrasonic stimulation,
for which
a sonotrode described herein may be used, does not require constant generation
of
ultrasonic energy. Rather, the ultrasonic waves or stimulation may be
generated
continuously or pulsed at acceptable frequencies. As long as the effects of
the
ultrasonic stimulation in the reservoir formation are continuous and are not
substantially reduced, the ultrasonic stimulation may be considered continuous
stimulation. For example, it may be expected certain effects of ultrasonic
stimulation
may decay quickly within tens of seconds or minutes. The ultrasonic
stimulation may
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be considered to be continuous, as long as such decay is not observed or has
no
material or observable effect on the treatment performance.
[0099] The frequency and energy intensity of the emitted ultrasonic waves
may be
selected dependent on various characteristics of the materials present in the
reservoir
and the fluids to be produced from the reservoir, such as initial viscosity,
porosity,
permeability, chemical or physical composition and structure, and the like.
Generally,
the ultrasonic waves may be emitted at a frequency of 10 to 50 kHz, such as
from
about 13 kHz to about 30 kHz, from about 15 kHz to about 30 kHz, or about 20
kHz.
The power of the ultrasonic waves may be from 1 to about 10 kW.
[00100] Other acoustic waves generated downhole may have a frequency from
about 20 Hz to about 10kHz.
[00101] Ultrasonic or sonochemical treatment of a wellbore and its
proximate
regions in the reservoir may last minutes, hours or days.
[00102] Depending on the length of the perforated section of well 520, or
the
length of the section of well 520 to be treated, and the total length of the
acoustic tool
unit, the acoustic tool unit and eventually the chemical injector may be moved
axially
along the length of well 520, so that all desired portions of well 520 and the
reservoir
formation nearby are subject to sonochemical or ultrasonic treatment, either
at the
same time or sequentially.
[00103] The ultrasonic or sonochemical treatment of a reservoir formation
may
be expected to improve permeability in the volume near the perforated wellbore
section of a vertical or a horizontal well. As can be appreciated by those
skilled in the
art, permeability may sometimes decrease due to clogging and other chemical or
physical effects during normal oil production. In such cases, ultrasonic or
sonochemical treatment may be reapplied to improve productivity.
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[00104] To achieve better or optimal results, the ultrasonic or
sonochemical
treatment may be designed and selected based on geophysical studies of the
particular reservoir to be treated. To achieve desired synergetic effects, the
selected
chemical agents may need to be injected directly into the same zone that is
under
acoustic treatment. The treatment zone may be selected from, or limited to,
zones that
are expected or known to be problematic, so that the overall treatment time
can be
controlled and limited for improved effectiveness and efficiency.
[00105] The treatment may be controlled and adjusted based on the feedback
and information obtained from downhole sensors or measurements, although the
data
may be processed and analysed at surface and control signals may be dispatched
at
surface. In this regard, signal wires 5115 and power wires 5114 in cable hose
5110
may be conveniently used.
[00106] Useful information that may be obtained from a downhole tool or
sensors
may include temperature, pressure, and fluid flow information.
[00107] During operation, the following properties of sonotrodes 5140 may
be
monitored, such as displayed at a control station at surface: power,
frequency, or the
like.
[00108] During treatment, information and data may be continuously
processed
to better control and adjust the treatment process based on the current status
and
expected development.
[00109] Other geophysical downhole tools (not shown) may be used during
operation and treatment. For example, such tools may be related to measurement
of,
downhole pressure, downhole temperature, natural radiation of the rock
formation in
the reservoir, downhole fluid flow, magnetic location of couplings,
thermoconductive
flow, electrical resistance, or soil/water content.
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[00110] The effectiveness of an ultrasonic or sonochennical treatment may
be
assessed by measuring fluid flow characteristics in the treated region
immediately
before and immediately after the treatment.
[00111] In some embodiments, the selection of equipment and downhole tools
or
materials to be used may be made to ensure that they are suitable for use and
operation under the particular downhole conditions. For example, they may be
selected for use under conditions at a temperature of up to 150 C or higher,
a
maximum pressure of 60 MPa, and in an acidic environment.
[00112] During or after treatment, fluids may be produced through tubing
524, or
the space between tubing 524 and casing 522, such as in a conventional manner,
as
can be understood by those skilled in the art.
[00113] While the particular embodiments described herein are illustrated
with a
horizontal well, and the described sonotrodes are particularly useful for
treating a
horizontal well in a reservoir containing viscous hydrocarbons, it should be
understood
that the sonotrodes as contemplated herein may also be applied in other wells,
including inclined wells or vertical wells, and in other types of reservoirs
of
hydrocarbons, where fluid mobility and blockage of fluid flow near or at a
perforated
wellbore section may likely occur.
[00114] In different embodiments, when both production wells and injection
wells
are used, both types of wells may be treated as described herein.
[00115] Typically, ultrasonic and sonochemical treatment of a well may be
performed during production "down-time". Conventional down-time is often
accompanied by optimization of the pumping equipment. In order to
differentiate
between the effects of ultrasound and normal workover we have measured the
influence of ultrasonic treatment and workover on the changes in the
productivity
factor of the oil well and water cut i.e. the percentage of water in the
recovered well
fluid. Ultrasonic treatment leads to an increase of the productivity factor by
39% and
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decrease of the water cut of the well by 5% on average. Whereas in wells where
only
the optimization of pumping equipment was carried out there was a drop in the
productivity factor of 5.6% and an increase in the water cut of 1.5%. The
tests
indicated that the success rate of the ultrasonic treatment of vertical wells
reaches 90%
and the increase in oil production is in the range of 40 to 100%.
[00116] Tests of sonochemical treatment were also conducted in horizontal
wells.
A 1 m thick formation was subjected to ultrasonic treatment after injection of
a
chemical reagent for 15 min. Before and after sonochemical treatment of the
well,
geophysical studies of the well were carried out. Based on the information
received the
zones for sonochemical treatment were determined. The treated area was 200 m
to
300 m long, the productive formation had a porosity of 0.27, the permeability
was
0.515 m2 and oil saturation was 0.67.
[00117] As a result of sonochemical treatment the production of fluid and
production of oil from all three treated wells grew. On average the production
of fluid
increased from 51 to 72 tons per day, and the production of oil from 23 to 33
tons per
day. In comparison with the sonochemical treatment of vertical wells in the
same
region the treatment of horizontal wells improved oil production but to a
lesser extent
as compared to similar treatment of vertical wells, and the reduction in water
use after
treatment was negligible.
[00118] Chemical reagents that have been used for test treatment of
horizontal
wells include acids, oxidants, enzymes and chelates. Potentially all of these
reagents
and others may be used for sonochemical treatment of wells or reservoir
formation.
[00119] Experimental results and theoretical estimations both show that the
optimal treatment time of ultrasonic enhanced oil recovery (EOR) in vertical
wells may
be about 60 min. However, in case of sonochemical treatment for horizontal
wells the
optimal treatment time may be reduced. Laboratory experiments have shown that
ultrasound can enhance the effect of chemicals used to improve the performance
of
vertical wells and to treat the wellbore perforation zone of horizontal wells.
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[00120] The waveguides and transducers described herein are also useful
for
other applications including use in either horizontal wells or vertical wells,
and in other
industries.
[00121] For example, a problem in the oil extraction process is the
reduced
productivity due to various reasons including reduced mobility of a fluid to
be produced
and progressive plugging of the pores of the reservoir in the well bore region
due to
accumulation of solids (clays, colloids, salts) that reduce the absolute
permeability or
interconnection of the pores. During production, fluids in the formation flow
through
perforations of the well into the well. The fluids entering the well may
include gas,
liquids and solids (particulates such as sand). The fluids may also include
materials
formed of heavy molecules. After a period of time, the pathways through the
perforations extended within the formation may be clogged. During fluid flow,
very
small solid particles (known as "fines") may tend to settle along the
pathways, and can
aggregate or coagulate, thus forming obstructions to fluid flow in the
formation pores
and reducing the production rate of fluids. As fluid flow slows down, more
"fines" can
settle, thus further reducing the fluid flow rate.
[00122] Dispersion of ultrasonic energy into the wellbore and the
formation near
the well can help to increase fluid flow or reduce the problem of clogging.
For effective
operation, the power of acoustic energy dispersed into the formation may be
more
than about 0.8 W/cm2.
[00123] Thus, a further example of using embodiments of waveguides and
transducers as described herein is illustrated in FIG. 6.
[00124] FIG. 6 illustrates a tool assembly 600 in a well 602 for
increasing
permeability in the wellbore region 612. Well 602 may be used to produce oil,
gas,
water, or a combination thereof. Tool assembly 600 provides acoustic
stimulation in
region 612, by generating not only acoustic waves propagating along the axial
direction of the well, but also substantial radially propagating acoustic
waves. As
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depicted, well 602 is a vertical well. In a different embodiment, similar
arrangements
may be made in a directional well or a well that is generally vertical on
inclined.
[00125] As depicted in FIG. 6, well 602 includes a metal casing 610,
cement wall
619 between casing 610 and wellbore region 612, an inner metal tubing 611
inside
casing 610, and a packer 615 between casing 610 and tubing 611. Casing 610
near
region 612 is perforated and has holes 613. Fissures 614 may be generated with
a
downhole tool in cement 619 and in region 612. Holes 613 and fissures 614
allow
fluids to flow from region 612 of the reservoir formation into well 602.
[00126] The wellbore of well 602 may contain a liquid phase 618 formed of
oil
and water. In some cases, a gas phase may also be present in the wellbore.
Tool
assembly 600 includes an acoustic device 620 positioned in the extraction zone
of the
wellbore, which is connected with a cable 622. Cable 22 may be a logging cable
and
carries power and signal transmission wires. Acoustic device 620 may include
waveguide 100, sonic device 200, sonic device 300, or modifications thereof as
described herein.
[00127] In this disclosure, the terms "oil", "hydrocarbons" or
"hydrocarbon" relate
to mixtures of varying compositions comprising hydrocarbons in the gaseous,
liquid or
solid states, which may be in combination with other fluids (liquids and
gases) that are
not hydrocarbons. For example, oil or hydrocarbons may include what are known
as
"light oil", "heavy oil", "extra heavy oil", or "bitumen". Viscous
hydrocarbons refer to
hydrocarbons occurring in semi-solid or solid form and having a viscosity in
the range
of about 1,000 to over 1,000,000 centipoise (mPa-s or cP) measured at original
in-situ
reservoir temperature. Depending on the in-situ density and viscosity of the
hydrocarbons, the hydrocarbons may comprise, for example, a combination of
light oil,
heavy oil, extra heavy oil and bitumen. Heavy crude oil, for example, may be
defined
as any liquid petroleum hydrocarbon having an American Petroleum Institute
(API)
Gravity of less than about 20 and a viscosity greater than 1,000 mPa.s. Oil
may be
defined, for example, as hydrocarbons mobile at typical reservoir conditions.
Extra
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heavy oil, for example, may be defined as having a viscosity of over 10,000
mPa.s and
about 10 API Gravity. The API Gravity of bitumen ranges from about 12 to
about 7
and the viscosity is greater than about 1,000,000 mPa-s. Native bitumen is
generally
non-mobile at typical native reservoir conditions.
[00128] A person skilled in the art will appreciate that in some
reservoirs, either
before or during oil production, fluid flow might be impeded by various
factors such as
low porosity, high viscosity of fluids, or the like. In some cases, at initial
(or original)
reservoir conditions (e.g., temperature or viscosity), before a reservoir has
been
treated with a chemical agent, heat, acoustic energy, or other means, the
reservoir
formation may have limited fluid mobility. In some cases, the fluid mobility
in a
reservoir may decrease after a period of oil production. In either of these
cases,
sonochemical or ultrasonic treatment of the formation through a well according
to an
embodiment of the present disclosure may conveniently increase fluid mobility
in the
formation.
[00129] Hydrocarbons in a reservoir of bituminous sands may be in a complex
mixture comprising interactions between sand particles, fines (e.g., clay),
and water
(e.g., interstitial water) which may form complex emulsions during processing.
The
hydrocarbons derived from bituminous sands may contain other contaminant
inorganic, organic or organometallic species which may be dissolved, dispersed
or
bound within suspended solid or liquid material. It remains challenging to
separate
hydrocarbons from the bituminous sands in-situ, which may impede production
performance of the in-situ process. Sonochemical treatment of such a reservoir
may
improve production performance.
[00130] Production performance may be improved when a higher amount of oil
is produced within a given period of time, or in some other manner as can be
understood by those skilled in the art. For example, production performance
may be
improved by increasing the flow rate of fluid from the reservoir into a
production well,
or the flow rate of fluid from an injection well into the reservoir, or both.
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[00131] Faster fluid flow in regions near a well and through perforations
of the
well can lead to more efficient oil production, and the increase in the flow
rate can be
indirectly indicated or measured by the increase in the rate of fluid
production or oil
production to the surface. The well may be a production well, or an injection
well. In
the latter case, improved fluid flow in or near the injection well may be
detected by
monitoring production rates at a production well in fluid communication with
the
injection well. Techniques for measurement of production rates have been well
developed and are known to those skilled in the art.
[00132] It can now be appreciated that embodiments the waveguides,
transducers and acoustic or sonic devices described herein may also be useful
in
other applications and fields, where more efficient radial dispersion of
acoustic energy
may be desirable.
[00133] For example, a device or tool described herein may be used for
extraction of water from water wells. A technique described herein may be
applied in
water wells or for cleaning large tanks filled with fluids, where an
ultrasonic device as
described may be deployed into the zone to be "cleaned" and operated in the
zone.
[00134] EXAMPLES
[00135] Simulation calculations were carried for embodiments of the tool as
depicted in FIG. 3A. Representative simulation results for distribution of
displacement
during oscillation of the tool on its own frequency 18.55 kHz are shown in
FIG. 7. The
data was obtained using a finite element method and a software program called
Eclipse.
[00136] The amplitudes of both radial and longitudinal oscillations were
calculated for sonic devices constructed according to FIG.3A with the length
of the
waveguide being 135 mm but with different shapes of the end portions in the
waveguide resonance chamber. The relative amplitudes of radial oscillation
were
calculated from these results. For comparison, similar calculations were also
carried
31
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out for sonic devices with similar constructions and dimensions but semi-
spherical or
flat end portions in the waveguide resonance chamber. The results are shown in
Table
II.
TABLE II. Relative Amplitudes of Radial Oscillation
Shape of End Cone Angle Relative Radial
Portion (20) Amplitude
Conoidal 90 2.32
Conoidal 100 2.50
Conoidal 110 2.50
Conoidal 120 2.41
Conoidal 130 2.35
Conoidal 140 2.37
Conoidal 150 2.21
Semi-Spherical 2.16
Flat 2.18
[00137] As can be seen from Table II, waveguides with conoidal end portions
provide increased radial oscillation as compared to flat or semi-spherical end
portions.
The highest relative radial oscillation amplitudes are expected for cone
angles (20) of
from about 100 to about 110 degrees. Improved results can be expected for cone
angles (28) at least from about 90 to about 150 degrees.
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[00138] CONCLUDING REMARKS
[00139] Other features, modifications, and applications of the embodiments
described here may be understood by those skilled in the art in view of the
disclosure
herein.
[00140] It will be understood that any range of values herein is intended
to
specifically include any intermediate value or sub-range within the given
range, and all
such intermediate values and sub-ranges are individually and specifically
disclosed.
[00141] It will also be understood that the word "a" or "an" is intended to
mean
"one or more" or "at least one", and any singular form is intended to include
plurals
herein.
[00142] It will be further understood that the term "comprise", including
any
variation thereof, is intended to be open-ended and means "include, but not
limited to,"
unless otherwise specifically indicated to the contrary.
[00143] When a list of items is given herein with an "or" before the last
item, any
one of the listed items or any suitable combination of two or more of the
listed items
may be selected and used.
[00144] Of course, the above described embodiments of the present
disclosure
are intended to be illustrative only and in no way limiting. The described
embodiments
are susceptible to many modifications of form, arrangement of parts, details
and order
of operation. The invention, rather, is intended to encompass all such
modification
within its scope, as defined by the claims.
33
