Note: Descriptions are shown in the official language in which they were submitted.
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RELEASING ACTIVATORS DURING WELLBORE OPERATIONS
TECHNICAL FIELD
This invention relates to wellbore operations and, more particularly, to
releasing
encapsulated activators during wellbore operations.
BACKGROUND
Some wellbores, for example, those of some oil and gas wells, use downhole
fluids
during operations such as drilling, cementing, and others. For example, a
downhole fluid may
be introduced into an annular space between the casing/drill string and the
surrounding earth.
As for cementing, the downhole fluid may secure the casing in the wellbore and
prevent
fluids from flowing vertically in the annulus between the casing and the
surrounding earth.
Different fluid formulations are designed for a variety of wellbore conditions
and operating
conditions, which may be above ambient temperature and pressure. In designing
a fluid
formulation, a number of potential mixtures may be evaluated to determine
their mechanical
properties under various conditions.
SUMMARY
In some implementations, a method for reducing material loss includes adding,
to a
downhole fluid circulated through a drill string, encapsulants encapsulating
one or more
activators. One or more parameters in a wellbore associated with a fault in
operating
conditions are determined. One or more energy waves in the downhole fluid
configured to
release the one or more activators from the encapsulants are emitted.
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The details of one or more embodiments of the invention are set forth in the
accompanying drawings and the description below. Other features, objects, and
advantages of the invention will be apparent from the description and
drawings, and from
the claims.
DESCRIPTION OF DRAWINGS
FIGURE 1 is an example well system for producing fluids from a production
zone;
FIGURE 2 is an example well system from producing fluids from a production
zone;
FIGURES 3A and 3B illustrate an example activation device for activating
cement slurry in a wellbore;
FIGURES 4A and 4B illustrate example processes for releasing activators in
cement slurries; and
FIGURE 5 is a flow chart illustrating an example method for updating one or
more properties of downhole fluid.
Like reference symbols in the various drawings indicate like elements.
DETAILED DESCRIPTION
The present disclosure is directed to one or more well systems having a fluid
delivery system that selectively releases activators configured to update one
or more
properties of a downhole fluid. For example, the described system may release
encapsulated active ingredients in selected subsurface locations in wells to
substantially
prevent loss of drilling fluid through a subsurface fracture or to control a
formation fluid
influx. A downhole fluid may include a settable material (e.g., cementing
fluid), a
drilling fluid, a completion fluid, a "kill" fluid (controls influxes), and/or
others. For
example, the downhole fluid may be a cementing fluid such that the released
chemicals
accelerate the associated setting rate. The one or more updated properties may
include a
setting rate, viscosity, solubility, lubrication, static gel strength (SGS)
development,
density, compressive strength development, and/or others. The activators may
be
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released in response to at least detecting formation pore fluid influx from or
downhole
fluid loss into one or more substerranean zones exceeding a predefined
threshold and
may be configured to activate and/or accelerate the setting process for a
cement fluid or
slurry in a wellbore. By dymanically altering the properties of a downhole
fluid, the
system may provide one or more of the following: major savings to the customer
would
include savings of rig time (¨$500K/day for deepwater rigs); savings of lost
drilling and
cementing fluids; reducing cement WOC time, eliminating remedial cementing
costs;
savings of time waiting on less effective systems (i.e. like Portland cement)
to set in +/- 8
hours; mitigate losses and/or influxes that cause loss of well control
incidents ($millions
damage costs) and/or others.
In some implementations, activators are enclosed in a shell or at least
partially
enclosed in a shell and released in response to encapsulation failure
triggered or
otherwise initiated by the system. Encapsulation Shell Failure (ESF) may
include
molecular resonation of fatigue fail chemical bonds, disruption of oriented
structures of
shells' emulsified interfacial phases, altering molecular surface charges of
shell
membranes, exceeding shell tensile or bond strengths to generate cracks or
other
openings in the encapsulating shells, resonance heating and expansion of
internal phases
to stress crack shells to induce internal phase leaks and/or releases, and/or
other failure
types caused or otherwise associated with energy waves. Energy waves may
include
sonic/ultrasonic acoustic sound signals, tuned frequency and/or amplitude
oscillating
pressure pulses (e.g. Coanda Effect), ultra-fast laser pulse induced
desorption,
vibrationally mediated photodissociation, electromagnetic, radio, and/or
microwave
waveforms, laser ablation, and/or other wave types. In some implmentations,
the
described systems may use energy waves (e.g., ultrasound, pressure pulses,
lasers,
radiation) to release activators configured to update one or more properties
of the
downhole fluid in response, for example, to detecting a fault in operating
conditions of
the wellbore. An operating fault may include loss of circulation fluid above a
specified
threshold, a stuck drilling pipe, a partially or fully occluded wellbore,
uncontrolled
formation fluid influxes (called "kicks"), underground blowouts (uncontrolled
flows of
formation fluids from one zone into another one), surface blowouts
(uncontrolled flows
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of formation fluids to the surface), and/or others. Alternatively or in
combination, the
energy waves may directly update physical properties of chemicals in the
downhole fluid
by using one or more different mechanisms responsive to energy waves. The one
or more
different mechanisms may include modifying chemical properties, releasing
chemicals,
modifying physical properties (e.g., particle size), updating operating
conditions (e.g.,
pressure, temperature), and/or other mechanisms responsive to energy waves.
For
example, described systems may use energy waves to directly heat chemicals to
increase
their reaction rate with other materials.
Referring to FIGURE 1, the system 100 is a cross-sectional well system 100
that
updates properties of downhole fluids in response to at least detecting a
operating fault.
In the illustrated implementation, the well system 100 includes a production
zone 102, a
non-production zone 104, wellbore 106, downhole fluid 108, and encapsulants
110. The
production zone 102 may be a subterranean formation including resources (e.g.,
oil, gas,
water). The non-production zone 104 may be one or more formations that are
isolated
from the wellbore 106 using cement and/or other isolators. For example, the
zone 104
may include contaminants that, if mixed with the resources, may result in
requiring
additional processing of the resources and/or make production economically
unviable.
The downhole fluid 108 may be pumped or selectively positioned in the wellbore
106,
and the properties of the downhole fluid 108 may be updated using the
encapsulants 110.
In some implementations, the encapsulants 110 may release activators in
response to
energy waves initiated by, for example, a user of the system 100. By remotely
controlling the properties, a user may configure the system 100 without
substantially
interferencing with wellbore operations.
While the figure illustrates using the
encapsulants with cementing operations, the encapsulants 108 may be used
during other
types of operations such as drilling without departing from the scope of this
disclosure.
Turning to a more detailed description of the elements of system 100, the
wellbore 106 extends from a surface 112 to the production zone 102. The
wellbore 106
may include a rig 114 that is disposed proximate to the surface 112. The rig
114 may be
coupled to a casing 116 that extends the entire length of the wellbore or a
substantial
portion of the length of the wellbore 106 from about the surface 112 towards
the
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production zones 102 (e.g., hydrocarbon-containing reservoir). In some
implementations,
the casing 116 can extend past the production zone 102. The casing 116 may
extend to
proximate a terminus 118 of the wellbore 106. In some implementations, the
well 106
may be completed with the casing 116 extending to a predetermined depth
proximate to
the production zone 102. In short, the wellbore 106 initially extends in a
substantially
vertical direction toward the production zone 102. In some implementations,
the
wellbore 106 may include other portions that are horizontal, slanted or
otherwise deviated
from vertical.
The rig 114 may be centered over a subterranean oil or gas formation 102
located
below the earth's surface 112. The rig 114 includes a work deck 124 that
supports a
derrick 126. The derrick 126 supports a hoisting apparatus 128 for raising and
lowering
pipe strings such as casing 116. Pump 130 is capable of pumping a variety of
downhole
fluids 108 (e.g., drilling fluid, cement) into the well and includes a
pressure measurement
device that provides a pressure reading at the pump discharge. The wellbore
106 has
been drilled through the various earth strata, including formation 102. Upon
completion
of wellbore drilling, the casing 116 is often placed in the wellbore 106 to
facilitate the
production of oil and gas from the formation 102. The casing 116 is a string
of pipes that
extends down wellbore 106, through which oil and gas will eventually be
extracted. A
cement or casing shoe 132 is typically attached to the end of the casing
string when the
casing string is run into the wellbore. The casing shoe 132 guides the casing
116 toward
the center of the hole and may minimize or otherwise decrease problems
associated with
hitting rock ledges or washouts in the wellbore 106 as the casing string is
lowered into
the well. The casing shoe 132 may be a guide shoe or a float shoe, and
typically
comprises a tapered, often bullet-nosed piece of equipment found on the bottom
of the
casing string 116. The casing shoe 132 may be a float shoe fitted with an open
bottom
and a valve that serves to prevent reverse flow, or U-tubing, of downhole
fluid 108 from
annulus 122 into casing 116 after the downhole fluid 108 has been placed into
the
annulus 122. The region between casing 116 and the wall of wellbore 106 is
known as the
casing annulus 122. To fill up casing annulus 122 and secure casing 116 in
place, casing
116 is usually "cemented" in wellbore 106, which is referred to as "primary
cementing."
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In some implementations, the downhole fluid 108 may be injected into the
wellbore 106
through one or more ports 134 in the casing shoe 132. The downhole fluid 108
may flow
through a hose 136 into the casing 116. In some instances where the casing 116
does not
extend the entire length of the wellbore 106 to the surface 112, the casing
116 may be
supported by a liner hanger 138 near the bottom of a previous casing 120. In
the
illustrated implementation, the casing shoe 132 includes a wave generator 140
including
any hardware, software or firmware configured to generate one or more energy
waves
proximate the terminus of the casing 116.
As previously mentioned, the wave generator 140 may generate energy waves
including one or more of the following: sonic and/or ultrasonic acoustic sound
signals,
tuned frequency and/or amplitude oscillating pressure pulses (e.g. Coanda
Effect), ultra-
fast laser pulse induced desorption, vibrationally mediated photodissociation,
electromagnetic, radio, and/or microwave waveforms, laser ablation, and/or
other wave
types. The ESF wave types and characteristics (frequency, amplitude,
bandwidth,
intensity, duration, etc.) may be selected to substantially match wave
attributes
configured to break or otherwise form openings in the specific encapsulating
shells. For
example, the selected wave attributes may isolate and carry the internal phase
materials
into the wellbore 106 and deliver them to the desired location without
significant leakage.
In addition, the selected wave attributes may be utilized to spatially tune
release of
encapsulates to within the confines of the wellbore 106 or also material
infiltrated into the
formation. In these instances, the activators may be delivered into pore space
prior to
activation, which may enable introducing co-reactants in place with mixed
encapsulant
systems. In regards to radio and/or microwaves, invert emulsion muds may be
broken to
facilitate recycling of the water and oil in refineries, oil production
facilities, etc. The
application may work by microwave (electromagnetic fields oscillating at 915
MHz)
treating oil/water emulsions to destabilize them by breaking down the physical
bonds
holding the emulsion together. This type of wave energy may be absorbed by
polar
and/or charged molecules, including the water and the surfactants, charged
solids and
polar asphaltene aggregates that stabilize the emulsion interface. As the wave
fields
oscillate, a temperature gradient may be established across the oil/water
interface, and the
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surface active molecules may begin to rotate and move about as they react to
the
changing fields. This may result in a breakdown of the surface and emulsion
stability. In
regards to ultrasonic waves, these waves may break nanobubbles to release
activators.
For example, micro-emulsions called nanobubbles in the downhole fluid may
transport
activators to precise locations within the wellbore where they are released by
ultrasonic
waves breaking the encapsulating micro-emulsions. In other words,
ultrasonic/sonic ESF
wave tools in the well may release the nanobubble encapsulated chemicals at
the desired
downhole locations without being exposed to contaminants that degrade
performance in
conventional placement methods.
In some implementations, the system 100 may update properties of the downhole
fluid 108 using the encapsulants 110 during one or more wellbore operations.
In some
implementations, the encapsulants 110 may be mixed into the downhole fluid 108
prior to
entering the casing 116, and the downhole fluid 108 may then be pumped down
the inside
of the casing 116. As previously mentioned, the encapsulants 110 may include
one or
more activators that update the properties of the downhole fluid 108 in
response to at
least an energy wave. For example, the leaking or otherwise released
activators may
trigger rapid gelation, hydration, swelling, expansion, foaming, and/or
setting of at least a
portion of the downhole fluid 108. For example, the activators may trigger,
intiate or
increase a setting rate of LCM (Lost Circulation Material) and/or other
drilling/completion/cementing fluid materials. The LCM and/or other material
systems
may be placed either pumping them into a zone and/or behind a pipe (casing,
liners,
drillpipe), and/or they can be activated as they pass through an ESF wave
downhole tool
such as the generator 140 while being pumped down and out of a working string
(as
illustrated). The encapsulants 110 may infiltrate pore space of the formation,
which may
allow for in-situ reactions such as pore-throat sealing and/or formation
stabilization.
Other encapsulants 110 may be released in selected intervals of the well,
which may
increase downhole fluid viscosity to help slow down and control "kicks"
migrating to the
surface and to decrease or stop uncontrolled flows in underground or surface
blowouts.
Additionally, the infiltrated encapsulants 110 may be tailored for later PE
applications
such as acidizing. Later triggering or releasing acidic materials may be able
to acidize
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from behind the filtercake. For instance, in response to detecting fluid loss
reaches a
specified threshold, the operator of the rig 114 may switch on the ESF wave
tool 140
placed near the end of a work string via, for example, surface controls.
During cementing operations (as illustrated), both primary and remedial
cementing may also utilize the encapsulated LCM or other encapsulated
materials such as
accelerators, surfactants, expanding agents (alumiunum powder, etc.), foaming
agents,
etc. For primary cementing, the ESF wave tool 140 may be installed in the
casing shoe
or float collar 132 as discussed above. In some implementations, the tool 140
may be a
non-retrievable, low-cost, and very small ESF tool such as the "Pulsonix"
device (PE PSL
product) or modified-version thereof that produces tuned frequency/amplitude
oscillating
pressure pulses (Coanda Effect) mounted either inside the bottom wiper plug or
inside the
float collar. When the bottom wiper plug seats on the float collar and its
rupture disc
opens to bypass the cement slurry, part of the slurry flows enters the ESF
wave tool's
flow channel to start sending ESF waves into all the slurry flowing into the
annulus 122.
As the encapsulating shells 110 are broken by the ESF waves' molecular
resonance
action, the encapsulated materials may be released and react in the annulus
122 and
perform various functions such as sealing loss zones, accelerating cement
strength
development, controlling gas migration (shortening SGS transit times,
activating latex or
GasCheck additives, etc.), creating in-situ foam cement, etc. For remedial
cementing, the
ESF wave tool 140 is mounted in a sub at or near the bottom of the work string
and either
continually or selectively operated (sending out ESF waves). The latter may be
started by
a dropping a dart or ball or by the same surface on/off tool controlling
signal described
above for drilling operations.
During drilling operations, ESF waves may be incident a pill of LCM laden
fluid
while it is being pumped out the bit (not illustrated). As the ESF waves pass
through the
LCM system, the encapsulated materials may be released to activate other LCM
components creating the types of compounds for effective sealing of the loss
zone
formation. After the activated LCM passes out of the bit and travels into the
loss zone,
the activators may rapidly react chemically into soft sealing agglomerates,
osmotically-
swelling hard particles, and/or a combination of both and seal off the zone.
If this proves
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not effective enough, a second type of LCM pill may be pumped in a similar
fashion. In
this case after passing the ESF wave tool and going out into the lost
circulation zone, the
LCM may begin to rapidly set into a hard sealing system. In other cases, the
customer
may add encapsulated LCM into the total circulating mud volume that is pumped
into and
out of the well such as during drilling operations. When drilling fluid losses
occur, the
operator may flip a switch on the surface control panel to start sending out
ESF waves
from the ESF tool (located inside or near the drill bit) to convert the
encapsulted LCM
into a loss zone sealing LCM system. The ESF tool may be switched off as
losses
diminish and returns are re-established within specified guidelines. An
example of non
LCM applications related to wellbore drilling, the encapsulant material may be
utilized
for real-time mud property alterations. The drilling fluid may be formulated
to contain an
encapsulated viscosity modifier, which upon release may specifically alter the
fluid
rheology in a near-bit region rather as compared with fluid cycling.
Such
spatial/temporal control may allow for rapid fluid tuning or may be used to
establish
highly viscous 'pills' in real-time for zonal isolation and/or other
applicaitons.
The potential encapsulated materials and descriptions of their system recipes
and applications may be customized for a plurality of different types of
operation. For
example, a well may being drilled with SBM (synthetic based mud) and severe
losses
indicate a large size fracture is taking the SBM flow out of the well. The
operator may
decide to apply the LCM encapsulated systems and have a ESF wave tool
installed in the
drill bit. One encapsulated LCM component may be the water phase of the SBM
invert
emulsion that contains high concentrations of cement acceleration chemicals
such as
CaC12. Other LCM system components may be selected based on the downhole
sealant
properties to seal large fractures. The operator may select a hard setting
sealant "pill"
with dry powdered cement and a second encapsulated component such as "dry
emulsion"
powder of LATEX 2000 (cement) added to the synthetic oil phase of the SBM to
make a
"pill" in the "slugging pit" on the rig. This pill may be a substantially
improved version
of the old LCM system called DOC (diesel oil cement) where the oil is an inert
carrying
fluid for the cement. The new LCM system may also utilizes the synthetic oil
as an inert
carrying fluid for both the cement and encapsulated latex. In addition, the
SBM's water
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phase may carry the cement's accelerating agent and hydration mixwater. The
ESF wave tool
may be tuned to break the SBM invert emulsion and may be switched on as the
new LCM
"pill" exits the drill bit. The ESF waves break the invert emulsion and
release the SBM water
phase that mixes and reacts with the cement and latex to create a fast setting
sealant squeezed
into and plugging the fracture near the wellbore.
As the fluid 108 reaches the bottom of casing 116, it flows out of casing 116
and into
casing annulus 122 between casing 116 and the wall of wellbore 106. In
connection with
pumping the downhole fluid 108 into the annulus, the generator 140 may emit
one or more
energy waves before, during, and/or after the pumping is complete to release
one or more
chemicals from the encapsulants 110. In response to at least the signal, the
encapsulants 110
may release chemicals that update the properties of the downhole fluid 108 in
the annulus
122. Some or all of the casing 116 may be affixed to the adjacent ground
material with set
cement as illustrated in FIGURES 2. In some implementations, the casing 116
comprises a
metal. After setting, the casing 116 may be configured to carry a fluid, such
as air, water,
natural gas, or to carry an electrical line, tubular string, or other
elements.
After positioning the casing 116, a settable slurry 108 including encapsulants
110 may
be pumped into annulus 122 by a pump truck (not illustrated). While the
following discussion
will center on the settable slurry 108 comprising a downhole fluid 108, the
settable slurry 108
may include other compounds such as resin systems, settable muds, conformance
fluids, lost
circulation, and/or other settable compositions. Example cement slurries 108
are discussed in
more detail below. In connecting with depositing or otherwise positioning the
downhole fluid
108 in the annulus 122, the encapsulants 110 may release activators to
activate or otherwise
increase the setting rate of the downhole fluid 108 in response to at least
ultrasound. In other
words, the released activators may activate the downhole fluid 108 to set
cement in the
annulus 122. The settable composition sets in a range from about one minute to
about 24
hours after reacting with the one or more activators.
In some implementations, the encapsulants 110 may release an activator that
initiates
or accelerates the setting of the downhole fluid 108. For example, the
downhole fluid 108
may remain in a substantially slurry state for a specified period of time, and
the encapsulants
110 may activate the cement slurry in response to ultrasound. In some
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instances, ultrasound may crack, break or otherwise form one or more holes in
the
encapsulants 110 to release the activators. In some instances, the ultrasound
may
generate heat that melts one or more holes in the encapsulants 110. The
encapsulants 110
enclose the activators with, for example, a membrane such as a polymer (e.g.,
polystyrene, ethylene/vinyl acetate copolymer, polymethylmethacrylate,
polyurethanes,
polylactic acid, polyglycolic acid, polyvinylalcohol, polyvinylacetate,
hydrolyzed
ethylene/vinyl acetate, or copolymers thereof). The encapsulant 110 may
include other
materials responsive to ultrasound. In these implementations, the encapsulant
110 may
include a polymer membrane that ultrasonically degrades to release the
enclosed
activators. In some examples, an ultrasonic signal may structurally change the
membrane
to release the activators such as, for example, opening a preformed slit in
the
encapsulants 110. In some implementations, at least one dimension of the
encapsulants
110 may be microscopic such as in range from 10 nanometers (nm) to 15,000 nm.
For
example, the dimensions of the encapsulants 110 may be on a scale of a few
tens to about
one thousand nanometers and may have one or more external shapes including
spherical,
cubic, oval and/or rod shapes. In some implementations, the encapsulants 110
can be
shells with diameters in the range from about 10 nm to about 1,000 nm. In
other
implementations, the encapsulants 110 can include a diameter in a range from
about 15
micrometers to about 10,000 micrometers. Alternatively or in combination, the
encapsulants 110 may be made of metal (e.g., gold) and/or of non-metallic
material (e.g.,
carbon). In some implementations, the encapsulants 110 may be coated with
materials to
enhance their tendency to disperse in the downhole fluid 108. The encapsulants
110 may
be dispersed in the cement slurry at a concentration of 105 to 109
capsules/cm3. In some
implementations, the encapsulants 110 are a shell selected from the group
consisting of a
polystyrene, ethylene/vinyl acetate copolymer, and polymethylmethacrylate,
polyurethanes, polylactic acid, po lyglyco lic acid, polyvinylalcohol, po
lyvinylacetate,
hydrolyzed ethylene/vinyl acetate, and copolymers thereof.
FIGURE 2 illustrates a cross sectional view of the well system 100 including
activated set cement 202 in at least a portion of the subterranean zone 104.
In particular,
the encapsulants 110 released activators in response to at least detecting a
loss of the
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downhole fluid 108 such that the fluid 108 including the chemicals were
positioned in the
fault 204 to the set cement 202. In some implementations, the cement slurry
108 flowed
into the annulus 122 through the casing 116 and further into the fault 204. In
response to
at least a signal, the encapsulants 110 in the slurry 108 released one or more
chemicals
configured to accelerate the setting rate of the slurry 108. In the
illustrated example,
substantially all encapsulants 110 in the annulus 122 released activators to
form the set
cement 202 along substantially the entire length of the annulus 122. In some
implementations, the energy waves may be emitted for a specified period of
time to
substantially limit the formation of the set cement 204 in the fault 202. In
other words,
an initial amount of the cement slurry 108 may be exposed to energy waves such
that the
setting period may be substantially equal to a period of time for the setting
cement slurry
108 to enter to the fault 204.
FIGURES 3A and 3B illustrate an example encapsulant 110 of FIGURE 1 in
accordance with some implementations of the present disclosure. In this
implementation,
the encapsulant 110 is substantially spherical but may be other shapes as
discussed above.
The encapsulant 110 is a shell 302 encapsulating one or more activators 304 as
illustrated
in FIGURE 3B. The encapsulant 110 releases one or more stored activators 304
in
response to at least one or more energy waves. For example, the encapsulant
110 may
crack or otherwise form one or more holes in response to at least the energy
waves. The
illustrated encapsulant 110 is for example purposes only, and the encapsulant
110 may
include some, none, or all of the illustrated elements without departing from
the scope of
this disclosure.
FIGURES 4A and 4B illustrate an example implementation of the encapsulant
110 including an opening configured to release one or more activators. The
encapsulants
110 may release activators by heating one or more portions to form at least
one opening,
destroying or otherwise removing one or more portions, and/or other processes
for
forming an opening in the shell 302. The following implementations are for
illustration
purposes only, and the encapsulants 110 may release activators using some, all
or none of
these processes.
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Referring to FIGURE 4A, the encapsulant 110 forms an opening through heat
formed from wave energy. For example, the ultrasonic signals may directly heat
the
membrane of the encapsulant 110 and/or heat the surrounding downhole fluid 108
to a
temperature above the melting point. The encapsulant 110 may be a gold shell
that when
vibrated at its natural frequency melts at least a portion of the shell to
release the enclosed
activators. In these instances, the generated heat may melt or otherwise
deform the shell
to form an opening. In addition to metal membranes, the encapsulant 110 may be
other
materials such as a polymer. Referring to FIGURE 4B, the encapsulant 110 forms
cracks, breaks, or openings in the shell in response one or more energy waves.
For
example, an ultrasonic signal may crack or otherwise destroy portions of the
encapsulant
110. In some implementations, the ultrasound may form defects in the membrane
of the
shell 302 and, as a result, form one or more openings as illustrated.
FIGURES 5 is a flow diagram illustrating an example method 500 for releasing
one or more chemicals in response to at least an operating fault. The
illustrated methods
are described with respect to well system 100 of FIGURE 1, but these methods
could be
used by any other system. Moreover, well system 100 may use any other
techniques for
performing these tasks. Thus, many of the steps in these flowcharts may take
place
simultaneously and/or in different order than as shown. The well system 100
may also
use methods with additional steps, fewer steps, and/or different steps, so
long as the
methods remain appropriate.
Referring to FIGURE 5, method 500 begins at step 502 where activators are
selected based, at least in part, on one or more parameters. For example, the
encapsulants
110 and the enclosed chemicals may be selected be based, at least in part, on
components
of the downhole fluid 108 and/or current wellbore operations. In some
implementations,
the encapsulants 110 may be selected based on downhole conditions (e.g.,
temperature).
At step 504, the selected activators are mixed with a downhole fluid. In some
examples,
the encapsulants 110 may be mixed with the downhole fluid 108 as the truck 130
pumps
the fluid 108 into the casing 116. In some examples, the encapsulants 110 may
be mixed
with dry ingredients prior to generating the downhole fluid 108. Next, at step
506, the
downhole fluid, including the activators, is pumped downhole. In some
instances, the
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CA 02853441 2015-09-02
downhole fluid 108 including the encapsulants 110 may be pumped into the
annulus 122 at a
specified rate. At step 508, an indication of operating fault is received. For
example, the
system 100 may detect that a fluid loss exceeds a threshold, a partially
occluded wellbore, a
stuck pipe, and/or other operating faults. Next, at step 510, an energy wave I
selected based
on the type of fault. For example, the downhole fluid 108 may include a
plurality of different
types of encapsulants 110 such that each type releases the associated
chemicals in response to
a different energy wave. In doing so, the system 100 may be prepared to
address a plurality of
different operating faults. One or more energy waves are transmitted to the at
least a portion
of the downhole fluid at step 512. Again in the example, the generator 134 may
transmit
signals at a portion of the downhole fluid 108. In this example, the
transmitted signals may
release chemicals proximate the shoe 132 to update one or more properties of
that portion of
the downhole fluid 108. In some instances, the casing 116 may be moved (e.g.,
up/down) to
assist in distributing the activators as desired.
The scope of the claims should not be limited by the preferred embodiments set
forth
in the examples, but should be given the broadest interpretation consistent
with the
description as a whole.
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