U.S. patent application number 13/302982 was filed with the patent office on 2013-05-23 for releasing activators during wellbore operations.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is Daniel Lee Bour, Gregory Perez, Ronald Sweatman, Carl Thaemlitz. Invention is credited to Daniel Lee Bour, Gregory Perez, Ronald Sweatman, Carl Thaemlitz.
Application Number | 20130126164 13/302982 |
Document ID | / |
Family ID | 48425691 |
Filed Date | 2013-05-23 |
United States Patent
Application |
20130126164 |
Kind Code |
A1 |
Sweatman; Ronald ; et
al. |
May 23, 2013 |
RELEASING ACTIVATORS DURING WELLBORE OPERATIONS
Abstract
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.
Inventors: |
Sweatman; Ronald;
(Montgomery, TX) ; Bour; Daniel Lee; (Granite
Falls, WA) ; Thaemlitz; Carl; (Cypress, TX) ;
Perez; Gregory; (Pearland, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Sweatman; Ronald
Bour; Daniel Lee
Thaemlitz; Carl
Perez; Gregory |
Montgomery
Granite Falls
Cypress
Pearland |
TX
WA
TX
TX |
US
US
US
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
48425691 |
Appl. No.: |
13/302982 |
Filed: |
November 22, 2011 |
Current U.S.
Class: |
166/282 ;
166/90.1 |
Current CPC
Class: |
E21B 21/003 20130101;
C09K 8/516 20130101; C09K 8/467 20130101; C09K 8/035 20130101 |
Class at
Publication: |
166/282 ;
166/90.1 |
International
Class: |
E21B 43/22 20060101
E21B043/22; E21B 43/12 20060101 E21B043/12 |
Claims
1. A method for reducing material loss, comprising: adding to a
downhole fluid circulated through a drill string encapsulants
encapsulating one or more activators; determining one or more
parameters in a wellbore associated with a fault in operating
conditions; and emitting one or more energy waves in the downhole
fluid configured to release the one or more activators from the
encapsulants.
2. The method of claim 1, further comprising determining a location
associated with a subset of encapsulants, wherein the one or more
activators are released at least proximate the determined
location.
3. The method of claim 1, wherein the released chemicals are
configured to react with the downhole fluid.
4. The method of 1, wherein the one or more energy waves are
emitted in response to at least determining a rate of loss of the
downhole fluid exceeds a specified threshold.
5. The method of claim 1, wherein the downhole fluid includes a
settable composition, and the one or more released activators are
configured to increase a setting rate of the settable
composition.
6. The method of claim 5, wherein the settable composition
comprises at least one of a cement composition, a resin
composition, a settable mud, a conformance fluid, a lost
circulation composition, an influx or blowout controlling fluid, or
a polymeric additive.
7. The method claim 5, wherein the settable composition sets in a
range from about one minute to about 24 hours after reacting with
the one or more chemicals.
8. The method of claim 2, wherein the one or more conditions
comprises a drill pipe incorrectly positioned in the wellbore.
9. The method of claim 1, wherein the one or more activators are
enclosed in a shell that releases the one or more activators in
response to at least the one or more energy waves.
10. The method of claim 9, wherein at least one dimension of the
shell is from about 10 nanometers to about 1 millimeter.
11. The method of claim 1, wherein the one or more parameters
comprise an obstruction in the wellbore.
12. The method of claim 1, wherein the downhole fluid comprises a
drilling fluid, and the one or more released activators alter a
viscosity of the drilling fluid.
13. The method of claim 1, wherein the one or more energy waves
comprises at least one of sonic signals, ultrasonic signals,
microwave, or radio waves.
14. The method of claim 1, further comprising remotely activating,
at a surface of the wellbore, a signal generator affixed at least
proximate a terminus of a drilling string.
15. A system, comprising: a dispenser configured to add, to a
downhole fluid circulated through a drill string, encapsulants
encapsulating one or more activators; one or more sensors
configured to determine one or more parameters in a wellbore
associated with a fault in operating conditions; and a transmitter
configured to emit one or more energy waves in the downhole fluid
configured to release the one or more activators from the
encapsulants.
16. The system of claim 15, a location module configured to
determine a location associated with a subset of encapsulants,
wherein the one or more activators are released at least proximate
the determined location.
17. The system of claim 15, wherein the released chemicals are
configured to react with the downhole fluid.
18. The system of claim 15, wherein the one or more energy waves
are emitted in response to at least determining a rate of loss of
the downhole fluid exceeds a specified threshold.
19. The system of claim 15, wherein the downhole fluid includes a
settable composition, and the one or more released activators are
configured to increase a setting rate of the settable
composition.
20. The system of claim 19, wherein the settable composition
comprises at least one of a cement composition, a resin
composition, a settable mud, a conformance fluid, a lost
circulation composition, an influx or blowout controlling fluid, or
a polymeric additive.
21. The system of claim 19, wherein the settable composition sets
in a range from about one minute to about 24 hours after reacting
with the one or more chemicals.
22. The system of claim 16, wherein the one or more conditions
comprises a drill pipe incorrectly positioned in the wellbore.
23. The system of claim 15, wherein the one or more activators are
enclosed in a shell that releases the one or more activators in
response to at least the one or more energy waves.
24. The system of claim 23, wherein at least one dimension of the
shell is from about 10 nanometers to about 1 millimeter.
25. The system of claim 15, wherein the one or more parameters
comprise an obstruction in the wellbore.
26. The system of claim 15, wherein the downhole fluid comprises a
drilling fluid, and the one or more released activators alter a
viscosity of the drilling fluid.
27. The system of claim 15, wherein the one or more energy waves
comprises at least one of sonic signals, ultrasonic signals,
microwave, or radio waves.
28. The system of claim 15, further comprising a trigger configured
to remotely activate, at a surface of the wellbore, a signal
generator affixed at least proximate a terminus of a drilling
string.
Description
TECHNICAL FIELD
[0001] This invention relates to wellbore operations and, more
particularly, to releasing encapsulated activators during wellbore
operations.
BACKGROUND
[0002] 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
[0003] 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.
[0004] 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
[0005] FIG. 1 is an example well system for producing fluids from a
production zone;
[0006] FIGS. 3A and 3B illustrate an example activation device for
activating cement slurry in a wellbore;
[0007] FIGS. 4A and 4B illustrate example processes for releasing
activators in cement slurries; and
[0008] FIG. 5 is a flow chart illustrating an example method for
updating one or more properties of downhole fluid.
[0009] Like reference symbols in the various drawings indicate like
elements.
DETAILED DESCRIPTION
[0010] 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 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 (.about.$500K/day for deepwater rigs); savings of lost
drilling and cementing fluids; reducing cement WOC time,
eliminating remedial cementing costs; savings of time waiting on
less effective systems (i.e. like Portland cement) to set in +/-8
hours; mitigate losses and/or influxes that cause loss of well
control incidents ($millions damage costs) and/or others.
[0011] 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
implementations, 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 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.
[0012] Referring to FIG. 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.
[0013] 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 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.
[0014] 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." 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.
[0015] 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 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.
[0016] 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
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.
[0017] 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 (aluminum 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.
[0018] 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 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 encapsulated
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 applications.
[0019] 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 CaCl.sub.2. 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
phase may carry the cement's accelerating agent and hydration mix
water. 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.
[0020] 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 FIG. 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.
[0021] 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.
[0022] 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 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 10.sup.5 to 10.sup.9
capsules/cm.sup.3. 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, polyglycolic acid,
polyvinylalcohol, polyvinylacetate, hydrolyzed ethylene/vinyl
acetate, and copolymers thereof.
[0023] FIG. 2A illustrate 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 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.
[0024] FIGS. 3A and 3B illustrate an example encapsulant 110 of
FIG. 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 FIG. 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.
[0025] FIGS. 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.
[0026] Referring to FIG. 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 FIG. 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.
[0027] FIG. 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 FIG. 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.
[0028] Referring to FIG. 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 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.
[0029] A number of embodiments of the invention have been
described. Nevertheless, it will be understood that various
modifications may be made without departing from the spirit and
scope of the invention. Accordingly, other embodiments are within
the scope of the following claims.
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