Note: Descriptions are shown in the official language in which they were submitted.
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MONITORING DOWNHOLE PARAMETERS USING MEMS
CROSS-REFERENCE TO RELATED APPLICATIONS
This application claims priority to 14/919,975 filed October 22, 2015 and is a
Continuation-in-Part Application of U.S. Patent Application No. 13/855,463,
filed April 2, 2013,
entitled "Surface Wellbore Operating Equipment Utilizing MEMS Sensors", which
is a
Continuation-in-Part Application of U.S. Patent Application 13/664,286, filed
October 30, 2012,
and entitled "Use of Sensors Coated with Elastomer for Subterranean
Operations," which is a
continuation-in-part of U.S. Patent Application 12/618,067, filed November 13,
2009, now U.S.
Patent No. 8,342,242 issued January 1, 2013, and entitled "Use of Micro-
Electro-Mechanical
Systems (MEMS) in Well Treatments," which is a Continuation-in-Part
Application of U.S.
Patent Application 11/695,329 filed April 2, 2007, now U.S. Patent 7,712,527
issued May 11,
2010, and entitled "Use of Micro-Electro-Mechanical Systems (MEMS) in Well
Treatments,"
each of which is hereby incorporated by reference herein in its entirety.
BACKGROUND OF THE INVENTION
This disclosure relates to the field of drilling, completing, servicing, and
treating a
subterranean well such as a hydrocarbon recovery well. In particular, the
present disclosure
relates to methods for detecting and/or monitoring the position and/or
condition of wellbore
servicing compositions, for example wellbore sealants such as cement, using
data sensors (for
example, MEMS-based sensors) coated with an elastomer. Still more
particularly, the present
disclosure describes methods of monitoring the integrity and performance of
wellbore servicing
compositions over the life of the well using data sensors (for example, MEMS-
based sensors)
coated with an elastomer. Additionally, the present disclosure describes
methods of monitoring
conditions and/or parameters of wellbore servicing compositions during
wellbore operations at
the surface of a wellsite and before placement into the wellbore.
Natural resources such as gas, oil, and water residing in a subterranean
formation or zone
are usually recovered by drilling a wellbore into the subterranean formation
while circulating a
drilling fluid in the wellbore. After terminating the circulation of the
drilling fluid, a string of
pipe (e.g., casing) is run in the wellbore. The drilling fluid is then usually
circulated downward
through the interior of the pipe and upward through the annulus, which is
located between the
exterior of the pipe and the walls of the wellbore. Next, primary cementing is
typically
performed whereby a cement slurry is placed in the annulus and permitted to
set into a hard mass
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(i.e., sheath) to thereby attach the string of pipe to the walls of the
wellbore and seal the annulus.
Subsequent secondary cementing operations may also be performed. One example
of a
secondary cementing operation is squeeze cementing whereby a cement slurry is
employed to
plug and seal off undesirable flow passages in the cement sheath and/or the
casing. Non-
cementitious sealants are also utilized in preparing a wellbore. For example,
polymer, resin, or
latex-based sealants may be desirable for placement behind casing.
To enhance the life of the well and minimize costs, sealant slurries are
chosen based on
calculated stresses and characteristics of the formation to be serviced.
Suitable sealants are
selected based on the conditions that are expected to be encountered during
the sealant service
life. Once a sealant is chosen, it is desirable to monitor and/or evaluate the
health of the sealant
so that timely maintenance can be performed and the service life maximized.
The integrity of
sealant can be adversely affected by conditions in the well. For example,
cracks in cement may
allow water influx while acid conditions may degrade cement. The initial
strength and the
service life of cement can be significantly affected by its moisture content
from the time that it is
placed. Moisture and temperature are the primary drivers for the hydration of
many cements and
are critical factors in the most prevalent deteriorative processes, including
damage due to
freezing and thawing, alkali-aggregate reaction, sulfate attack and delayed
Ettringite
(hexacalcium aluminate trisulfate) formation. Thus, it is desirable to measure
one or more sealant
parameters (e.g., moisture content, temperature, pH and ion concentration) in
order to monitor
sealant integrity.
Active, embeddable sensors can involve drawbacks that make them undesirable
for use in a
wellbore environment. For example, low-powered (e.g., nanowatt) electronic
moisture sensors
are available, but have inherent limitations when embedded within cement. The
highly alkali
environment can damage their electronics, and they are sensitive to
electromagnetic noise.
Additionally, power must be provided from an internal battery to activate the
sensor and transmit
data, which increases sensor size and decreases useful life of the sensor.
Accordingly, an
ongoing need exists for improved methods of monitoring wellbore servicing
compositions, for
example a sealant condition.
SUMMARY OF SOME OF THE EMBODIMENTS
Disclosed herein is a method comprising mixing a wellbore servicing
composition
comprising Micro-Electro-Mechanical System (MEMS) sensors m surface wellbore
operating
equipment at the surface of a wellsite.
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Further disclosed herein a wellbore servicing system comprising surface
wellbore
operating equipment placed at a surface of a wellsite, a wellbore servicing
composition
comprising a plurality of Micro-Electro-Mechanical System (MEMS) sensors,
wherein the
wellbore servicing composition is located within the surface wellbore
operating equipment, and
an interrogator placed in communicative proximity with one or more of the
plurality of MEMS
sensors, wherein the interrogator activates and receives data from the one or
more of the plurality
of MEMS sensors in the wellbore servicing composition at the surface of the
wellsite.
Further disclosed herein is a method comprising placing a wellbore servicing
composition
comprising a Micro-Electro-Mechanical System (MEMS) sensor m a wellbore and/or
subterranean formation, wherein the sensor is coated with an elastomer. The
elastomer- coated
sensor is configured and operable to detect one or more parameters, including
a compression or
swelling of the elastomer, an expansion of the elastomer, or a change in
density of the
composition.
Also disclosed herein is a method comprising placing a Micro-Electra-
Mechanical System
(MEMS) sensor in a wellbore and/or subterranean formation, placing a wellbore
servicing
composition in the wellbore and/or subterranean formation, and using the MEMS
sensor to
detect a location of the wellbore servicing composition, wherein the sensor is
coated with an
elastomer.
Also disclosed herein is a method comprising placing a Micro-Electro-
Mechanical System
(MEMS) sensor in a wellbore and/or subterranean formation, placing a wellbore
servicing
composition in the wellbore and/or subterranean formation, and using the MEMS
sensor to
monitor a condition of the wellbore servicing composition, wherein the sensor
is coated with an
elastomer.
Further disclosed herein is a method comprising placing one or more Micro-
Electro-
Mechanical System (MEMS) sensors in a wellbore and/or subterranean formation,
placing a
wellbore servicing composition in the subterranean formation, using the one or
more MEMS
sensors to detect a location of at least a portion of the wellbore servicing
composition, and using
the one or more MEMS sensors to monitor at least a portion of the wellbore
servicing
composition, wherein the one or more sensors are coated with an elastomer.
Further disclosed herein is a method comprising placing one or more Micro-
Electro-
Mechanical System (MEMS) sensors in a wellbore and/or subterranean formation
using a
wellbore servicing composition, and monitoring a condition using the one or
more MEMS
sensors, wherein the one or more sensors are coated with an elastomer.
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Further disclosed herein is a method comprising placing one or more Micro-
Electro-
Mechanical System (MEMS) sensors in a wellbore and/or subterranean formation
using a
wellbore servicing composition, wherein the one or more MEMS sensors comprise
an amount
from about 0.001 to about 10 weight percent of the wellbore servicing
composition, wherein the
one or more sensors are coated with an elastomer.
Further disclosed herein is a method comprising placing one or more Micro-
Electro-
Mechanical System (MEMS) sensors in CO2 injection, storage or disposal well in
a subterranean
formation, and monitoring a condition using the one or more MEMS sensors,
wherein the one or
more sensors are coated with an elastomer.
Further disclosed herein is a method comprising placing a wellbore servicing
composition
comprising a plurality of elastomer-coated sensors in a wellbore, a
subterranean formation, or
both.
Further disclosed herein is a wellbore servicing composition comprising a base
fluid and a
plurality of elastomer-coated sensors.
The foregoing has outlined rather broadly the features and technical
advantages of the
present disclosure in order that the detailed description that follows may be
better understood.
Additional features and advantages of the apparatus and method will be
described hereinafter
that form the subject of the claims of this disclosure. It should be
appreciated by those skilled in
the art that the conception and the specific embodiments disclosed may be
readily utilized as a
basis for modifying or designing other structures for carrying out the same
purposes of the
present disclosure. It should also be realized by those skilled in the art
that such equivalent
constructions do not depart from the spirit and scope of the apparatus and
method as set forth in
the appended claims.
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BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the disclosed embodiments of the present
disclosure, reference
will now be made to the accompanying drawing in which:
Figure 1 is a flowchart illustrating an embodiment of a method in accordance
with the
present disclosure.
Figure 2 is a schematic of a typical onshore oil or gas drilling rig and
wellbore.
Figure 3 is a flowchart detailing a method for determining when a reverse
cementing
operation is complete and for subsequent optional activation of a downhole
tool.
Figure 4 is a flowchart of a method for selecting between a group of sealant
compositions
according to one embodiment of the present disclosure.
Figure 5A is a schematic view of an embodiment of a wellbore servicing system
according
to the disclosure.
Figure 5B is a schematic view of another embodiment of a wellbore servicing
system
according to the disclosure.
Figure 6 is a flowchart illustrating an embodiment of a method according to
the disclosure.
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DETAILED DESCRIPTION
Disclosed herein are wellbore servicing compositions (also referred to as
wellbore
compositions, servicing compositions, wellbore servicing fluids, wellbore
fluids, servicing
fluids, and the like) comprising one or more sensors optionally coated with an
elastomer and
methods for utilizing the compositions. As used herein, "elastomer" includes
any material or
combination of materials which has a tendency to deform and/or compress under
an applied
force and a further tendency to re-form and/or expand upon removal of the
applied force, without
substantial adverse effect to the structure of the material. As used herein,
"wellbore servicing
composition" includes any composition that may be prepared or otherwise
provided at the
surface and placed down the wellbore, typically by pumping. As used herein, a
"sealant" refers
to a fluid used to secure components within a wellbore or to plug or seal a
void space within the
wellbore. Sealants, and in particular cement slurries and non-cementitious
compositions, are
used as wellbore compositions in several embodiments described herein, and it
is to be
understood that the methods described herein are applicable for use with other
wellbore
compositions and/or servicing operation. The wellbore servicing compositions
disclosed herein
may be used to drill, complete, work over, fracture, repair, treat, or in any
way prepare or service
a wellbore for the recovery of materials residing in a subterranean formation
penetrated by the
wellbore. Examples of wellbore servicing compositions include, but are not
limited to, cement
slurries, non-cementitious sealants, drilling fluids or muds, spacer fluids,
fracturing fluids, base
fluids of variable-density fluids, or completion fluids. The wellbore
servicing compositions are
for use in a wellbore that penetrates a subterranean formation, and it will be
understood that a
wellbore servicing composition that is pumped downhole may be placed in the
wellbore, the
surrounding subterranean formation, or both as will be apparent in the context
of a given
servicing operation. It is to be understood that "subterranean formation"
encompasses both areas
below exposed earth and areas below earth covered by water such as ocean or
fresh water. The
wellbore may be a substantially vertical wellbore and/or may contain one or
more lateral
wellbores, for example as produced via directional drilling. As used herein,
components are
referred to as being "integrated" if they are formed on a common support
structure placed in
packaging of relatively small size, or otherwise assembled in close proximity
to one another.
Embodiments of methods include detecting and/or monitoring the position and/or
condition of wellbore servicing compositions and/or the wellborc/ surrounding
formation using
data sensors comprising Micro-Electro-Mechanical System (MEMS) sensors.
Embodiments of
methods include detecting and/or monitoring the position and/or condition of
wellbore servicing
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compositions and/or the wellbore/surrounding formation using data sensors
(e.g., MEMS
sensors) which are coated with an elastomer (also referred to herein as
"elastomer-coated
sensors"). Also disclosed herein are methods of monitoring the integrity and
performance of the
wellbore servicing compositions, for example during a given wellbore servicing
operation and/or
over the life of a well, using elastomer-coated sensors (e.g., elastomer-
coated MEMS sensors).
Also disclosed herein are methods for determining and/or monitoring a
condition and/or
parameter of a wellbore servicing composition at the surface of a wellsite,
for example during
mixing or blending of a wellbore servicing composition comprising MEMS
sensors.
Performance may be indicated by changes, for example, in various parameters,
including, but not
limited to, expansion or swelling of the elastomer, compression of the
elastomer, and moisture
content, pressure, density, temperature, pH, and various ion concentrations
(e.g., sodium,
chloride, and potassium ions) of the composition.
In embodiments, the methods may comprise the use of embeddable data sensors
(e.g.,
MEMS sensors, optionally comprising an elastomer coating, embedded in a
wellbore servicing
composition) capable of detecting parameters in a wellbore servicing
composition, for example a
sealant such as cement. In embodiments, the methods provide for evaluation of
a sealant during
mixing, placement, and/or curing of the sealant within the wellbore. In
another embodiment, the
method is used for sealant evaluation from placement and curing throughout its
useful service
life, and where applicable, to a period of deterioration and repair. In
embodiments, the methods
of this disclosure may be used to prolong the service life of the sealant,
lower costs, and enhance
creation of improved methods of remediation. Additionally, methods are
disclosed for
determining the location of sealant within a wellbore, such as for determining
the location of a
cement slurry during primary cementing of a wellbore as discussed further
hereinbelow.
Additionally, methods are disclosed for detecting a structural feature such as
crack in the
composition, e.g., a sealant such as cement, as discussed further hereinbelow.
Discussion of an embodiment of a method of the present disclosure will now be
made with
reference to the flowchart of Figure 1, which includes methods of placing a
wellbore servicing
composition comprising one or more sensors (e.g., MEMS sensors optionally
comprising an
elastomer coating) in a subterranean formation. The elastomer-coated sensors
may generally be
used to gather various types of data or information as described herein. At
block 100, elastomer-
coated data sensors are selected based on the parameter(s) or other conditions
to be determined
or sensed within the subterranean formation. At block 102, a quantity of
elastomer-coated data
sensors is mixed with a wellbore servicing composition, for example, a sealant
slurry. In
embodiments, data sensors coated with elastomer are added to the wellbore
servicing
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composition (e.g., a sealant) by any methods known to those of skill in the
art. For example, for a
wellbore servicing composition formulated as a sealant (e.g., a cement
slurry), the elastomer-
coated sensors may be mixed with a dry material, mixed with one more liquid
components (e.g.,
water or a non- aqueous fluid), or combinations thereof. The mixing may occur
onsite, for
example sensors may be added into a surface bulk mixer such as a cement slurry
mixer, a gel
blender (as depicted in Figure 5A), a sand blender (as depicted in Figure 5A),
a conduit or other
component stream, or combinations thereof. The elastomer-coated sensors may be
added directly
to the mixer, may be added to one or more component streams and subsequently
fed to the
mixer, may be added downstream of the mixer, or combinations thereof. In
embodiments,
elastomer-coated data sensors are added after a blending unit and slurry pump,
for example,
through a lateral by-pass. The elastomer-coated sensors may be metered in and
mixed at the
wellsite, or may be pre-mixed into the wellbore servicing composition (or one
or more
components thereof) and subsequently transported to the wellsite. For example,
the sensors may
be dry mixed with dry cement and transported to the wellsite where a cement
slurry is formed
comprising the sensors. Alternatively or additionally, the sensors may be pre-
mixed with one or
more liquid components (e.g., mix water) and transported to the wellsite where
a cement slurry is
formed comprising the sensors. The properties of the wellbore composition or
components
thereof may be such that the sensors distributed or dispersed therein do not
substantially settle or
stratify during transport or placement.
The wellbore servicing composition (e.g., a sealant slurry and elastomer-
coated sensors) is
then pumped downhole at block 104, whereby the sensors are positioned or
placed within the
wellbore. For example, the sensors may extend along all or a portion of the
length of the
wellbore (e.g., in an annular space adjacent casing) and/or into the
surrounding formation (e.g.,
via a fissure or fracture). The composition may be placed downhole as part of
a primary
cementing, secondary cementing, or other sealant operation as described in
more detail herein.
At block 106, a data interrogator tool is positioned in an operable location
to gather data from the
elastomer-coated sensors, for example lowered within the wellbore proximate
the sensors. At
block 108, the data interrogator tool interrogates the elastomer-coated
sensors (e.g., by sending
out an RF signal) while the data interrogator tool traverses all or a portion
of the wellbore
containing the sensors. The elastomer-coated data sensors are activated to
record and/or transmit
data at block 110 via the signal from the data interrogator tool. At block
112, the data
interrogator tool communicates the data to one or more computer components
(e.g., memory
and/or microprocessor) that may be located within the tool, at the surface, or
both. The data may
be used locally or remotely from the tool to calculate the location of each
elastomer-coated data
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sensor and correlate the measured parameter(s) to such locations to evaluate
performance of the
wellbore servicing composition (e.g., sealant).
Data gathering, as shown in blocks 106 to 112 of Figure 1, may be carried out
at the time
of initial placement in the well of the servicing composition comprising
elastomer-coated
sensors, for example during drilling (e.g., a composition comprising drilling
fluid and elastomer-
coated MEMS sensors) or during cementing (e.g., a composition comprising a
cement slurry and
elastomer-coated MEMS sensors) as described in more detail below. Additionally
or
alternatively, data gathering may be carried out at one or more times
subsequent to the initial
placement in the well of the composition comprising elastomer-coated sensors.
For example,
data gathering may be carried out at the time of initial placement in the well
of the composition
comprising elastomer- coated sensors or shortly thereafter to provide a
baseline data set. As the
well is operated for recovery of natural resources over a period of time, data
gathering may be
performed additional times, for example at regular maintenance intervals such
as every 1 year, 5
years, or 10 years. The data recovered during subsequent monitoring intervals
can be compared
to the baseline data as well as any other data obtained from previous
monitoring intervals, and
such comparisons may indicate the overall condition of the wellbore. For
example, changes in
one or more sensed parameters may indicate one or more problems in the
wellbore and/or
surrounding formation. Alternatively, consistency or uniformity in sensed
parameters may
indicate no substantive problems in the wellbore and/or surrounding formation.
In an
embodiment, data (e.g., sealant parameters) from a plurality of monitoring
intervals is plotted
over a period of time, and a resultant graph is provided showing an operating
or trend line for the
sensed parameters. Atypical changes in the graph as indicated for example by a
sharp change in
slope or a step change on the graph may provide an indication of one or more
present problems
or the potential for a future problem. Accordingly, remedial and/or preventive
treatments or
services may be applied to the wellbore to address present or potential
problems.
In embodiments, the wellbore servicing composition may be formulated as a
sealant (e.g.,
a cementitious slurry) comprising elastomer-coated sensors. The sealant may
comprise any
wellbore sealant known in the art. Examples of sealants include cementitious
and non-
cementitious sealants both of which are well known in the art. In embodiments,
non-cementitious
sealants comprise resin based systems, latex based systems, or combinations
thereof. In
embodiments, the sealant comprises a cement slurry with styrene-butadiene
latex (e.g., as
disclosed in U.S. Patent No. 5,588,488 incorporated by reference herein in its
entirety). Sealants
may be utilized in setting expandable casing, which is further described
hereinbelow. In other
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embodiments, the sealant is a cement utilized for primary or secondary
wellbore cementing
operations, as discussed further hereinbelow.
The sealant may include a sufficient amount of water to form a pumpable
slurry. The water
may be fresh water or salt water (e.g., an unsaturated aqueous salt solution
or a saturated aqueous
salt solution such as brine or seawater). In embodiments, the cement slurry
may be a lightweight
cement slurry containing foam (e.g., foamed cement) and/or hollow
beads/microspheres. In an
embodiment, elastomer-coated MEMS sensors are incorporated into or attached to
all or a
portion of the hollow microspheres. Additionally or alternatively, the
elastomer-coated sensors
may be dispersed within the cement along with the microspheres. Examples of
sealants
containing microspheres are disclosed in U.S. Patent Nos. 4,234,344;
6,457,524; and 7,174,962,
each of which is incorporated herein by reference in its entirety. In an
embodiment, the
elastomer-coated sensors are incorporated into a foamed cement such as those
described in more
detail in U.S. Patent Nos. 6,063,738; 6,367,550; 6,547,871; and 7,174,962,
each of which is
incorporated by reference herein in its entirety.
In some embodiments, additives may be included in the sealant for improving or
changing
the properties thereof. Examples of such additives include but are not limited
to accelerators, set
retarders, defoamers, fluid loss agents, weighting materials, dispersants,
density- reducing
agents, formation conditioning agents, lost circulation materials, thixotropic
agents, suspension
aids, or combinations thereof. Other mechanical property modifying additives,
for example,
fibers, polymers, resins, latexes, and the like can be added to further modify
the mechanical
properties. These additives may be included singularly or in combination.
Methods for
introducing these additives and their effective amounts are known to one of
ordinary skill in the
art.
In embodiments, the sealant and elastomer-coated sensors may be placed
substantially
within the annular space between a casing and the wellbore wall. That is,
substantially all of the
elastomer-coated sensors are located within or in close proximity to the
annular space. In an
embodiment, the wellbore servicing fluid comprising the elastomer-coated
sensors does not
substantially penetrate, migrate, or travel into the formation from the
wellbore. In an alternative
embodiment, substantially all of the elastomer-coated sensors are located
within, adjacent to, or
in close proximity to the wellbore, for example less than or equal to about 1
foot, 3 feet, 5 feet,
or 10 feet from the wellbore. Such adjacent or close proximity positioning of
the sensors with
respect to the wellbore is in contrast to placing sensors in a fluid that is
pumped into the
formation in large volumes and substantially penetrates, migrates, or travels
into or through the
formation, for example as occurs with a fracturing fluid or a flooding fluid.
Thus, in
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embodiments, the elastomer- coated sensors are placed proximate or adjacent to
the wellbore (in
contrast to the formation at large), and provide information relevant to the
wellbore itself and
compositions (e.g., sealants) used therein (again in contrast to the formation
or a producing zone
at large).
In embodiments, the sealant comprising elastomer-coated sensors may be allowed
to set
(e.g., in the annulus described above, in a subterranean formation, etc.). For
example, the sealant
may be cementitious and may comprise a hydraulic cement that sets and hardens
by reaction
with water. Examples of hydraulic cements include but are not limited to
Portland cements (e.g.,
classes A, B, C, G, and H Portland cements), pozzolana cements, gypsum
cements, phosphate
cements, high alumina content cements, silica cements, high alkalinity
cements, shale cements,
acid/base cements, magnesia cements, fly ash cement, zeolite cement systems,
cement kiln dust
cement systems, slag cements, micro-fine cement, metakaolin, and combinations
thereof.
Examples of sealants are disclosed in U.S. Patent Nos. 6,457,524; 7,077,203;
and 7,174,962,
each of which is incorporated herein by reference in its entirety. In an
embodiment, the sealant
comprises a sorel cement composition, which typically comprises magnesium
oxide and a
chloride or phosphate salt which together form for example magnesium
oxychloride. Examples
of magnesium oxychloride sealants are disclosed in U.S. Patent Nos. 6,664,215
and 7,044,222,
each of which is incorporated herein by reference in its entirety.
In additional or alternative embodiments, the wellbore servicing composition
may be
formulated as a drilling fluid comprising elastorner-coated sensors. Various
types of drilling
fluids, also known as muds or drill-in fluids have been used in well drilling,
such as water-based
fluids, oil-based fluids (e.g., mineral oil, hydrocarbons, synthetic oils,
esters, etc.), gaseous
fluids, or a combination thereof. Drilling fluids typically contain suspended
solids. Drilling fluids
may form a thin, slick filter cake on the formation face that provides for
successful drilling of the
wellbore and helps prevent loss of fluid to the subterranean formation. In an
embodiment, at least
a portion of the elastomer-coated sensors remain associated with the filter
cake (e.g., disposed
therein) and may provide information as to a condition (e.g., thickness)
and/or location of the
filter cake. Additionally or in the alternative, at least a portion of the
elastomer-coated sensors
remain associated with drilling fluid and may provide information as to a
condition and/or
location of the drilling fluid.
In additional or alternative embodiments, the wellbore servicing composition
may be
formulated as a fracturing fluid comprising elastomer-coated sensors.
Generally, a fracturing
fluid comprises a fluid or mixture of fluids that when placed downhole under
suitable conditions,
induces fractures within the subterranean formation. Hydrocarbon-producing
wells often are
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stimulated by hydraulic fracturing operations, wherein a fracturing fluid may
be introduced into
a portion of a subterranean formation penetrated by a wellbore at a hydraulic
pressure sufficient
to create, enhance, and/or extend at least one fracture therein. Stimulating
or treating the
wellbore in such ways increases hydrocarbon production from the well. In some
embodiments,
the elastomer- coated sensors may be contained within a wellbore servicing
composition that
when placed downhole enters and/or resides within one or more fractures within
the subterranean
formation. In such embodiments, the elastomer-coated sensors provide
information as to the
location and/or condition of the fluid and/or fracture during and/or after
treatment. In an
embodiment, at least a portion of the elastomer-coated sensors remain
associated with a
fracturing fluid and may provide information as to the condition and/or
location of the fluid.
Fracturing fluids often contain proppants that are deposited within the
formation upon placement
of the fracturing fluid therein, and in an embodiment a fracturing fluid
contains one or more
proppants and one or more elastomer-coated sensors. In an embodiment, at least
a portion of the
elastomer-coated sensors remain associated with the proppants deposited within
the formation
(e.g., a proppant bed) and may provide information as to the condition (e.g.,
thickness, density,
settling, stratification, integrity, etc.) and/or location of the proppants.
Additionally or in the
alternative at least a portion of the elastomer-coated sensors remain
associated with a fracture
(e.g., adhere to and/or retained by a surface of a fracture) and may provide
information as to the
condition (e.g., length, volume, etc.) and/or location of the fracture. For
example, the elastomer-
coated sensors may provide information useful for ascertaining the fracture
complexity.
In additional or alternative embodiments, the wellbore servicing composition
may be
formulated as a gravel pack fluid comprising elastomer-coated sensors. Gravel
pack fluids may
be employed in a gravel packing treatment. The elastomer-coated sensors may
provide
information as to the condition and/or location of the composition during
and/or after the gravel
packing treatment. Gravel packing treatments are used, inter alia, to reduce
the migration of
unconsolidated formation particulates into the wellbore. In gravel packing
operations,
particulates, referred to as gravel, are carried to a wellbore in a
subterranean producing zone by a
servicing fluid known as carrier fluid. That is, the particulates are
suspended in a carrier fluid,
which may be viscosified, and the carrier fluid is pumped into a wellbore in
which the gravel
pack is to be placed. As the particulates are placed in the zone, the carrier
fluid leaks off into the
subterranean zone and/or is returned to the surface. The resultant gravel pack
acts as a filter to
separate formation solids from produced fluids while permitting the produced
fluids to flow into
and through the wellbore. When installing the gravel pack, the gravel is
carried to the formation
in the form of a slurry by mixing the gravel with a viscosified carrier fluid.
Such gravel packs
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may be used to stabilize a formation while causing minimal impairment to well
productivity. The
gravel, inter alia, acts to prevent the particulates from occluding the screen
or migrating with the
produced fluids, and the screen, inter alia, acts to prevent the gravel from
entering the wellbore.
In an embodiment, the wellbore servicing composition (e.g., gravel pack fluid)
comprises a
carrier fluid, gravel and one or more elastomer coated MEMS sensors. In an
embodiment, at
least a portion of the elastomer-coated sensors remains associated with the
gravel deposited
within the wellbore and/or subterranean formation (e.g., a gravel pack/bed)
after removal of the
carrier fluid and may provide information as to the condition (e.g.,
thickness, density, settling,
stratification, integrity, etc.) and/or location of the gravel pack/bed.
In additional or alternative embodiments, the wellbore servicing composition
may be
formulated as a spacer fluid comprising elastomer-coated sensors. Spacer
fluids may be used to
separate two other fluids (e.g., two other wellbore servicing fluids) from one
another, due to a
specialized purpose for the separated fluids, a possibility of contamination,
incompatibility (e.g.,
chemically), or combinations thereof. For example, a spacer fluid (e.g., an
aqueous fluid such as
water) may be used to separate a sealant and a drilling fluid in the wellbore
during cementing
operations. In embodiments, the elastomer-coated sensors may provide
information regarding the
location, position, integrity, flow, etc. of the spacer fluid.
In additional or alternative embodiments, the wellbore servicing composition
may be
formulated as a completion fluid comprising elastomer-coated sensors.
Completion fluids may
be used to prevent damage to a well upon completion, and for example may
comprise brines
such as formates, chlorides, or bromides. In embodiments, the elastomer-coated
sensors may
provide information regarding the location, position, of the completion fluid,
and additionally or
alternatively, the integrity of the completed well over the life of the well.
In additional or alternative embodiments, the wellbore servicing composition
may
comprise a base fluid (e.g., an aqueous fluid, oleaginous fluid, or both) and
one or more
elastomer- coated sensors. In such embodiments, the wellbore servicing
composition may be
referred to as a variable-density fluid. The density of the variable-density
fluid may vary as a
function of pressure. For example, the variable-density fluid may encounter
higher pressures
(e.g., as the wellbore servicing composition is placed downhole) than at a
previous pressure (e.g.,
the pressure at sea level), and the elastomer coatings compress against the
sensors and decrease
the volume of the elastomer coating of the sensors, and thus, of the elastomer-
coated sensors.
The decrease in volume of the elastomer-coated sensors increases the density
of the variable-
density fluid. In embodiments, the density of the variable-density fluid may
increase from 0.1%
to 300% of the density of the variable-density fluid at earth or sea level.
Likewise, the variable-
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density fluid may encounter lower pressures (e.g., as the wellbore servicing
composition is
moved upward through the wellbore, into a low pressure environment in the
subterranean
formation, or combinations thereof) than at a previous pressure (e.g., a
downhole pressure, a
pressure of a subterranean formation, or combinations thereof), and the
elastomer coatings
expand and increase the volume of the elastomer-coated sensors. The increase
in volume of the
elastomer-coated sensors decreases the density of the variable-density fluid.
In embodiments, the variable density fluid may vary in density at particular
phases of a
subterranean operation (e.g., drilling, fracturing, or the like) as may be
necessary to adapt to the
subterranean conditions to which the fluid is subjected. For example, where
the variable density
fluid is utilized in offshore drilling applications, the variable density
fluid may have a lower
density when located above the ocean floor, and subsequently have a higher
density when
located within the well bore beneath the ocean floor. Generally, the variable
density fluid may
have a density in the range of about 4 lb/gallon to about 18 lb/gallon when
measured at sea level.
When utilized in offshore applications, the variable density fluids may have a
density in the
range of about 6 lb/gallon to about 20 lb/gallon, measured when at a point of
maximum
compression.
In embodiments, the base fluid of the variable density fluid may comprise an
aqueous-
based fluid, a non-aqueous-based fluid, or mixtures thereof. When aqueous-
based, the water
utilized can be fresh water, salt water (e.g., water containing one or more
salts dissolved therein),
brine (e.g., saturated salt water), seawater, or combinations thereof.
Generally, the water can be
from any source provided that it does not contain an excess of compounds that
may adversely
affect other components in the variable density fluid. When non-aqueous-based,
the base fluid
may comprise any number of organic fluids. Examples of suitable organic fluids
may include
mineral oils; synthetic oils; esters; hydrocarbons; oil; diesel; naturally
occurring oils such as
vegetable, plant, seed, or nut oils; the like; or combinations thereof.
Generally, any oil in which a
water solution of salts can be emulsified (or vice-versa) may be suitable for
use in a variable-
density fluid. Generally, the base fluid may be present in an amount
sufficient to form a
pumpable wellbore composition (e.g., a variable density fluid). For example,
the base fluid is
typically present in the disclosed composition in an amount in the range of
about 20% to about
99.99% by volume of the composition.
In one or more embodiments, the elastomer (i.e., the elastomer which coats the
sensors)
may comprise any material or combination of materials which has a tendency to
deform and/or
compress under an applied force and a further tendency to re-form and/or
expand upon removal
of the applied force, without substantial adverse effect to the structure of
the material. In
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additional or alternative embodiments, the elastomer may comprise any material
or combination
of materials which may swell when in contact with a certain fluid (e.g., a
hydrocarbon or water),
when subject to a temperature which causes swelling, when subject to a
pressure which causes
swelling, when subject to a particular pH, or combinations thereof. Suitable
elastomers may
comprise a specific gravity in the range of about 0.05 to about 2.00;
alternatively, in the range of
about 0.05 to about 0.99; alternatively, in the range of about 1.00 to about
2.00. In embodiments,
the elastomer may be shear resistant, fatigue resistant, substantially
impermeable to fluids
typically encountered in subterranean formations, or combinations thereof. In
embodiments, the
elastomer may comprise an isothermal compressibility factor in the range of
about 1.5x10-3
(I/psi) to about 1.5x10-9 (I/psi), where "isothermal compressibility factor"
is defined as a change
in volume with pressure, per unit volume of the elastomer, at a constant
temperature. In
embodiments, the elastomer may be suitable for use in temperatures up to about
500 F without
degrading. In additional or alternative embodiments, the elastomer coating may
be suitable for
use in pressures up to about 21,000 psi without crushing the sensors (e.g.,
MEMS sensors).
Suitable elastomers (e.g., for MEMS sensors comprising an elastomer coating)
may
comprise a polymer and/or copolymer that, at a given temperature and pressure,
changes volume
by expansion and compression, and consequently, may change the density of the
wellbore
composition (e.g., variable density fluid). In embodiments, the elastomer may
comprise a
copolymer of styrene and divinylbenzene; a copolymer of methylmethacrylate and
acrylonitrile;
a copolymer of styrene and acrylonitrile; a terpolymer of methylmethacrylate,
acrylonitrile, and
vinylidene dichloride; a terpolymer of styrene, vinylidene chloride, and
acrylonitrile; a phenolic
resin; polystyrene; or combinations thereof. Examples of suitable elastomers
are disclosed in
U.S. Patent No. 7,749,942, which is incorporated herein in its entirety. In
additional or
alternative embodiments, the elastomer may comprise a WellLife material,
which is an
elastomeric material commercially available from Halliburton.
Suitable elastomers, such as those described above, can be chosen according to
the ability
to withstand the temperatures and pressures associated with pumping and/or
circulating through
an annulus of a wellbore around a casing, into a subterranean formation,
through a drill bit, or
combinations thereof. Additionally or alternatively, suitable elastomers can
be chosen according
to the ability to withstand the temperatures and pressures associated with
curing and setting of
cements in a wellbore and/or subterranean formation. In embodiments where the
composition is
moved through wellbore equipment or a subterranean formation, the elastomer
may resist
adhering to the wellbore equipment (e.g., drill pipe, the drill bit) or the
subterranean formation.
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In embodiments, the sensors are coated with an elastomer by methods recognized
by those
skilled in the art with the aid of this disclosure. For example, the sensors
may be dipped in a
liquid comprising the elastomer which then forms an elastomer coating upon
drying.
Alternatively, the elastomer may be melted and the sensors mixed and
distributed into a molten
elastomer (e.g., via compounding and/or extruding) and subsequently
pelletized. Alternatively,
the elastomer may be spray coated upon the sensors. Alternatively, the
elastomer may be formed
(e.g., polymerized) in the presence of the sensors. For example, the sensors
(e.g., MEMS
sensors) may be fluidized in a gas phase polymerization process wherein the
sensors are coated
as reactants polymerize to form the elastomer coating. In an embodiment, the
sensors are coated
in combination with one or more additional particulate materials to be
employed in a given
wellbore servicing composition. For example, particulate material (e.g., sand,
gravel, etc.) and
sensors (e.g., MEMS sensors) could be mixed and then subjected to a coating
process of the type
described herein to yield an elastomer coated particulate mixture comprising
elastomer-coated
sensors (e.g., a elastomer-coated proppant material comprising sensors, and
elastomer-coated
gravel pack material comprising sensors, etc.). In embodiments, the thickness
of the elastomer
coating on the sensors may range from about 0.0001 mm to 10 mm; 0.0001 to 1
mm; 0.0001 to
0.1 mm; 0.001 to 10 mm; 0.001 to 1 mm; 0.001 to 0.1 mm; or any suitable range
within these
endpoints.
In embodiments, the sensors contained within the elastomer coatings may be
silicon- based
and/or non-silicon based. Silicon-based sensors utilize silicon, for example,
as a substrate for the
sensor. Non-silicon based sensors may include LCD sensors, conductive polymer
sensors, bio-
polymer sensors, or combinations thereof. In embodiments, the sensors may
comprise a polymer
diode which provides data at low frequencies, which enables the sensors to
provide information
through thicker mediums (e.g., the compositions disclosed herein, a
subterranean formation,
casing, a drill string, or combinations thereof) than would otherwise be
possible at frequencies
above the low frequencies of the polymer diode. Suitable sensors are disclosed
in U.S. Patent
No. 7,832,263, which is incorporated herein by reference in its entirety.
In additional or alternative embodiments, the sensors contained within the
elastomer
coatings may comprise micro-electromechanical systems (MEMS) comprising one or
more (and
typically a plurality of) MEMS devices, referred to herein as MEMS sensors.
Suitable MEMS
devices may be selected with the aid of this disclosure, e.g., a semiconductor
device with
mechanical features on the micrometer scale. The MEMS devices disclosed herein
may be on the
nanometer to micrometer scale. MEMS sensors embody the integration of
mechanical elements,
sensors, actuators, and electronics on a common substrate such as silicon or
non-silicon based
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substrates. MEMS elements may include mechanical elements which are movable by
an input
energy (electrical energy or other type of energy). Using MEMS, a sensor may
be designed to
emit a detectable signal based on a number of physical phenomena, including
thermal,
biological, optical, chemical, and magnetic effects or stimulation. MEMS
devices are minute in
size, have low power requirements, are relatively inexpensive and are rugged,
and thus are well
suited for use in wellbore servicing compositions and related operations.
In embodiments, the elastomer-coated sensors may sense one or more parameters
within
the wellbore, within a wellbore servicing fluid, within a subterranean
formation, or combinations
thereof. In embodiments, the one or more parameters may comprise temperature,
pH, moisture
content, ion concentration (e.g., chloride, sodium, and/or potassium ions),
well cement
characteristic data (e.g., stress, strain, cracks, voids, gaps, or
combinations thereof), expansion of
the elastomer, compression of the elastomer, swelling of the elastomer, other
parameters
disclosed herein, or combinations thereof. In embodiments, the elastomer-
coated sensors may
sense a change in configuration of the elastomer-coated sensor, for example a
change in the
deflection, stress, strain, and/or thickness of the elastomer coating (e.g.,
due to a change in
pressure and/or temperature), an activation or deactivation of the sensor
(e.g., due to a change in
one or more of the parameters described herein), a change in transmission
frequency, a change in
time between transmissions, or combinations thereof
In embodiments, the sensors coated with an elastomer (e.g., MEMS sensors, LCD
sensors,
conductive polymer sensors, bio-polymer sensors, or combinations thereof) may
provide
information as to a location, flow path/profile, volume, density, temperature,
pressure, the
presence or absence of a particular fluid (e.g., water, a hydrocarbon), or a
combination thereof,
for a drilling fluid, a fracturing fluid, a gravel pack fluid, or other
wellbore servicing fluid in real
time such that the effectiveness of such service may be monitored and/or
adjusted during
performance of the service to improve the result of same. Accordingly, the
elastomer-coated
sensors may aid in the initial performance of the wellbore service
additionally or alternatively to
providing a means for monitoring a wellbore condition or performance of the
service over a
period of time (e.g., over a servicing interval and/or over the life of the
well). For example, the
one or more elastomer-coated sensors may be used in monitoring a gas or a
liquid produced from
the subterranean formation. Elastomer-coated sensors present in the wellbore
and/or formation
may be used to provide information as to the condition (e.g., temperature,
pressure, flow rate,
composition, etc.) and/or location of a gas or liquid produced from the
subterranean formation.
In an embodiment, the elastomer-coated sensors provide information regarding
the composition
of a produced gas or liquid. For example, the elastomer-coated sensors may be
used to monitor
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an amount of water produced in a hydrocarbon producing well (e.g., amount of
water present in
hydrocarbon gas or liquid), an amount of undesirable components or
contaminants in a produced
gas or liquid (e.g., sulfur, carbon dioxide, hydrogen sulfide, etc. present in
hydrocarbon gas or
liquid), or a combination thereof.
In additional or alternative embodiments, the elastomer-coated sensors may
provide
information regarding the structural integrity of a wellbore servicing
composition (e.g., a
composition disclosed herein, such as a sealant comprising a cement) which has
set. For
example, the elastomer-coated sensors may be used to detect the presence or
absence of a fluid
(e.g., a hydrocarbon or water) present in compromised areas (e.g., cracks,
voids, gaps, chips) of
the cement. The elastomer-coated sensors may be used to detect the presence or
absence of a gas
or liquid. The elastomer coating of a sensor embedded within the composition
(e.g., set cement)
may expand and/or swell in the presence of the fluid (e.g., hydrocarbon),
creating a greater
pressure on the sensor which is detected by the sensor. The elastomer coating
of a sensor may
also retract and release the pressure of swelling or expansion upon removal of
the fluid from
presence at the elastomer coating of the sensors.
In addition or in the alternative, an elastomer-coated sensor incorporated
within one or
more of the wellbore servicing compositions disclosed herein may provide
information that
allows a condition (e.g., thickness, density, volume, settling,
stratification, etc.) and/or location
of the wellbore servicing composition within the subterranean formation to be
detected.
In embodiments, the sensors contained within the elastomer coating are ultra-
small, e.g.,
3mtn2, such that the elastomer-coated sensors are pumpable in the disclosed
wellbore servicing
compositions (e.g., a sealant slurry, a variable density fluid, a fracturing
mixture, etc.). In
embodiments, the MEMS device of the elastomer-coated sensor may be
approximately 0.01 mm2
to 1 mm2, alternatively 1 mm2 to 3 mm2, alternatively 3 mm2 to 5 mm2 , or
alternatively 5 mm2
to 10 mm2 . In embodiments, the elastomer-coated sensors may be approximately
0.01 mm2 to
10 mm2. In embodiments, the elastomer-coated data sensors are capable of
providing data
throughout the service life of the wellbore servicing composition (e.g., a set
cement). In
embodiments, the elastomer-coated data sensors are capable of providing data
for up to 100
years. In an embodiment, the composition comprises an amount of elastomer-
coated sensors
effective to measure one or more desired parameters. In various embodiments,
the wellbore
servicing composition comprises an effective amount of elastomer-coated
sensors such that
sensed readings may be obtained at intervals of about 1 foot, alternatively
about 6 inches, or
alternatively about 1 inch, along the portion of the wellbore containing the
elastomer-coated
sensors. In an embodiment, the elastomer-coated sensors may be present in the
disclosed
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wellbore servicing compositions in an amount of from about 0.001 to about 10
weight percent.
Alternatively, the elastomer-coated sensors may be present in the disclosed
wellbore servicing
compositions in an amount of from about 0.01 to about 5 weight percent.
In embodiments, the elastomer-coated sensors added to (e.g., mixed with) the
wellbore
servicing composition may comprise passive sensors that do not require
continuous power from
a battery or an external source in order to transmit real-time data.
Additionally or alternatively,
the elastomer-coated sensors may comprise an active material connected to
(e.g., mounted within
or mounted on the surface of) an enclosure, the active material being liable
to respond to a
wellbore parameter, and the active material being operably connected to (e.g.,
in physical contact
with, surrounding, or coating) a capacitive MEMS element. In embodiments, the
elastomer-
coated sensors of the present disclosure may comprise one or more active
materials that respond
to two or more the parameters described herein. In such a way, two or more
parameters may be
monitored.
Suitable active materials, such as dielectric materials, that respond in a
predictable and
stable manner to changes in parameters over a long period may be identified
according to
methods well known in the art, for example see, e.g., Ong, Zeng and Grimes. "A
Wireless,
Passive Carbon Nanotube-based Gas Sensor," IEEE Sensors Journal, 2, 2, (2002)
82-88; Ong,
Grimes, Robbins and Singl, "Design and application of a wireless, passive,
resonant-circuit
environmental monitoring sensor," Sensors and Actuators A, 93 (2001) 33-43,
each of which is
incorporated by reference herein in its entirety. MEMS sensors suitable for
the methods of the
present disclosure that respond to various wellbore parameters are disclosed
in U.S. Patent No.
7,038,470 B 1 that is incorporated herein by reference in its entirety.
In embodiments, the sensors encased in the elastomer coatings are coupled with
radio
frequency identification devices (RFIDs) and can thus detect and transmit
parameters and/or well
cement characteristic data for monitoring the cement during its service life.
RFIDs combine a
microchip with an antenna (the RFID chip and the antenna are collectively
referred to as the
"transponder" or the "tag"). The antenna provides the RFID chip with power
when exposed to a
narrow band, high frequency electromagnetic field from a transceiver. A dipole
antenna or a coil,
depending on the operating frequency, connected to the RFID chip, powers the
transponder when
current is induced in the antenna by an RF signal from the transceiver's
antenna. Such a device
can return a unique identification "ID" number by modulating and re-radiating
the radio
frequency (RF) wave. Passive RF tags are gaining widespread use due to their
low cost,
indefinite life, simplicity, efficiency, ability to identify parts at a
distance without contact (tether-
free information transmission ability). These robust and tiny tags are
attractive from an
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environmental standpoint as they require no battery. The sensor and RFID tag
are preferably
integrated into a single component (e.g., chip or substrate), or may
alternatively be separate
components operably coupled to each other. In an embodiment, an integrated,
passive
MEMS/RFID elastomer-coated sensor contains a data sensing component, an
optional memory,
and an RFID antenna, whereby excitation energy is received and powers up the
sensor, thereby
sensing a present condition and/or accessing one or more stored sensed
conditions from memory
and transmitting same via the RFID antenna.
Within the United States, commonly used operating bands for RFID systems
center on one
of the three government assigned frequencies: 125 kHz, 13.56 MHz or 2.45 GHz.
A fourth
frequency, 27.125 MHz, has also been assigned. When the 2.45 GHz carrier
frequency is used,
the range of an RFID chip can be many meters. While this is useful for remote
sensing, there
may be multiple transponders within the RF field. In order to prevent these
devices from
interacting and garbling the data, anti-collision schemes are used, as are
known in the art. In
embodiments, the data sensors are integrated with local tracking hardware to
transmit their
position as they flow within a sealant slurry. The data sensors may form a
network using wireless
links to neighboring data sensors and have location and positioning capability
through, for
example, local positioning algorithms as are known in the art. The sensors may
organize
themselves into a network by listening to one another, therefore allowing
communication of
signals from the farthest sensors towards the sensors closest to the
interrogator to allow
uninterrupted transmission and capture of data. In such embodiments, the
interrogator tool may
not need to traverse the entire section of the wellbore containing elastomer-
coated sensors in
order to read data gathered by such sensors. For example, the interrogator
tool may only need to
be lowered about half-way along the vertical length of the wellbore containing
elastomer-coated
sensors. Alternatively, the interrogator tool may be lowered vertically within
the wellbore to a
location adjacent to a horizontal arm of a well, whereby elastomer-coated
sensors located in the
horizontal arm may be read without the need for the interrogator tool to
traverse the horizontal
arm. Alternatively, the interrogator tool may be used at or near the surface
and read the data
gathered by the sensors distributed along all or a portion of the wellbore.
For example, sensors
located distal to the interrogator may communicate via a network formed by the
sensors as
described previously.
In embodiments, the elastomer-coated sensors comprise passive (remain
unpowered when
not being interrogated) sensors energized by energy radiated from a data
interrogator tool. The
data interrogator tool may comprise an energy transceiver sending energy
(e.g., radio waves) to
and receiving signals from the elastomer-coated sensors and a processor
processing the received
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signals. The data interrogator tool may further comprise a memory component, a
communications component, or both. The memory component may store raw and/or
processed
data received from the elastomer-coated sensors, and the communications
component may
transmit raw data to the processor and/or transmit processed data to another
receiver, for
example located at the surface. The tool components (e.g., transceiver,
processor, memory
component, and communications component) are coupled together and in signal
communication
with each other.
In an embodiment, one or more of the data interrogator components may be
integrated into
a tool or unit that is temporarily or permanently placed downhole (e.g., a
downhole module). In
an embodiment, a removable downhole module comprises a transceiver and a
memory
component, and the downhole module is placed into the wellbore, reads data
from the elastomer-
coated sensors, stores the data in the memory component, is removed from the
wellbore, and the
raw data is accessed. Alternatively, the removable downhole module may have a
processor to
process and store data in the memory component, which is subsequently accessed
at the surface
when the tool is removed from the wellbore. Alternatively, the removable
downhole module may
have a communications component to transmit raw data to a processor and/or
transmit processed
data to another receiver, for example located at the surface. The
communications component
may communicate via wired or wireless communications. For example, the
downhole component
may communicate with a component or other node on the surface via a cable or
other
communications/telemetry device such as a radio frequency, electromagnetic
telemetry device or
an acoustic telemetry device. The removable downhole component may be
intermittently
positioned downhole via any suitable conveyance, for example wire-line, coiled
tubing, straight
tubing, gravity, pumping, etc., to monitor conditions at various times during
the life of the well.
In embodiments, the data interrogator tool comprises a permanent or semi-
permanent
downhole component that remains downhole for extended periods of time. For
example, a semi-
permanent downhole module may be retrieved and data downloaded once every few
years.
Alternatively, a permanent downhole module may remain in the well throughout
the service life
of well. In an embodiment, a permanent or semi-permanent downhole module
comprises a
transceiver and a memory component, and the downhole module is placed into the
wellbore,
reads data from the elastomer-coated sensors, optionally stores the data in
the memory
component, and transmits the read and optionally stored data to the surface.
Alternatively, the
permanent or semi- permanent downhole module may have a processor to process
and sensed
data into processed data, which may be stored in memory and/or transmit to the
surface. The
permanent or semi-permanent downhole module may have a communications
component to
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transmit raw data to a processor and/or transmit processed data to another
receiver, for example
located at the surface. The communications component may communicate via wired
or wireless
communications. For example, the downhole component may communicate with a
component or
other node on the surface via a cable or other communications/telemetry device
such as a radio
frequency, electromagnetic telemetry device or an acoustic telemetry device.
In embodiments, the data interrogator tool comprises an RF energy source
incorporated
into its internal circuitry and the data sensors are passively energized using
an RF antenna, which
picks up energy from the RF energy source. In an embodiment, the data
interrogator tool is
integrated with an RF transceiver. In embodiments, the elastomer-coated
sensors (e.g.,
MEMS/RFID sensors) are empowered and interrogated by the RF transceiver from a
distance,
for example a distance of greater than I Om, or alternatively from the surface
or from an adjacent
offset well. In an embodiment, the data interrogator tool traverses within a
casing in the well and
reads elastomer-coated sensors located in a sealant (e.g., cement) sheath
surrounding the casing
and located in the annular space between the casing and the wellbore wall. In
embodiments, the
interrogator senses the elastomer-coated sensors when in close proximity with
the sensors,
typically via traversing a removable downhole component along a length of the
wellbore
comprising the elastomer-coated sensors. In an embodiment, close proximity
comprises a radial
distance from a point within the casing to a planar point within an annular
space between the
casing and the wellbore. In embodiments, close proximity comprises a distance
of 0.1m to lm.
Alternatively, close proximity comprises a distance of 1 m to Sm.
Alternatively, close proximity
comprises a distance of from S m to 10m. In embodiments, the transceiver
interrogates the
sensor with RF energy at 125 kHz and close proximity comprises 0.1m to 0.25m.
Alternatively,
the transceiver interrogates the sensor with RF energy at 13.5 MHz and close
proximity
comprises 0.25m to 0.5m. Alternatively, the transceiver interrogates the
sensor with RF energy at
915 MHz and close proximity comprises 0.5m to 1 m. Alternatively, the
transceiver interrogates
the sensor with RF energy at 2.4 GHz and close proximity comprises lm to 2m.
In embodiments, the elastomer-coated sensors are incorporated into wellbore
cement and
used to collect data during and/or after cementing the wellbore. The data
interrogator tool may
be positioned downhole during cementing, for example integrated into a
component such as
casing, casing attachment, plug, cement shoe, or expanding device.
Alternatively, the data
interrogator tool is positioned downhole upon completion of cementing, for
example conveyed
downhole via wireline. The cementing methods disclosed herein may optionally
comprise the
step of foaming the cement composition using a gas such as nitrogen or air.
The foamed cement
compositions may comprise a foaming surfactant and optionally a foaming
stabilizer. The
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elastomer-coated sensors may be incorporated into a sealant composition and
placed downhole,
for example during primary cementing (e.g., conventional or reverse
circulation cementing),
secondary cementing (e.g., squeeze cementing), or other sealing operation
(e.g., behind an
expandable casing).
In primary cementing, cement is positioned in a wellbore to isolate an
adjacent portion of
the subterranean formation and provide support to an adjacent conduit (e.g.,
casing). The cement
forms a barrier that prevents fluids (e.g., water or hydrocarbons) in the
subterranean formation
from migrating into adjacent zones or other subterranean formations. In
embodiments, the
wellbore in which the cement is positioned belongs to a horizontal or
multilateral wellbore
configuration. It is to be understood that a multilateral wellbore
configuration includes at least
two principal wellbores connected by one or more ancillary wellbores.
Figure 2, which shows a typical onshore oil or gas drilling rig and wellbore,
will be used to
clarify the methods of the present disclosure, with the understanding that the
present disclosure is
likewise applicable to offshore rigs and wellbores. Rig 12 is centered over a
subterranean
formation 14 located below the earth's surface 16. Rig 12 includes a work deck
32 that supports a
derrick 34. Derrick 34 supports a hoisting apparatus 36 for raising and
lowering pipe strings such
as casing 20. Wellbore servicing system 30 is capable of pumping a variety of
wellbore
compositions (e.g., drilling fluid or cement) into the well and includes a
pressure measurement
device that provides a pressure reading at the pump discharge. The wellbore
servicing system 30
may fluidly connect to the wellbore 18, for example via a conduit (e.g.,
conduit 190 as shown in
Figures 5 and 6 and described hereinbelow). Wellbore 18 has been drilled
through the various
earth strata, including formation 14. Upon completion of wellbore drilling,
casing 20 is often
placed in the wellbore 18 to facilitate the production of oil and gas from the
formation 14.
Casing 20 is a string of pipes that extends down wellbore 18, through which
oil and gas will
eventually be extracted. A cement or casing shoe 22 is typically attached to
the end of the casing
string when the casing string is run into the wellbore 18. Casing shoe 22
guides casing 20 toward
the center of the hole and minimizes problems associated with hitting rock
ledges or washouts in
wellbore 18 as the casing string 20 is lowered into the well. Casing shoe, 22,
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 casing string 20. Casing shoe, 22, may be a float shoe
fitted with an open
bottom and a valve that serves to prevent reverse flow, or U-tubing, of cement
slurry from
annulus 26 into casing 20 as casing 20 is run into wellbore 18. The region
between casing 20 and
the wall of wellbore 18 is known as the casing annulus 26. To fill up casing
annulus 26 and
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secure casing 20 in place, casing 20 is usually "cemented" in wellbore 18,
which is referred to as
"primary cementing." A data interrogator tool 40 is shown in the wellbore 18.
In an embodiment, the method of this disclosure is used for monitoring primary
cement
during and/or subsequent to a conventional primary cementing operation. In
this conventional
primary cementing embodiment, sensors coated with an elastomer are mixed into
a cement
slurry, block 102 of Figure 1, and the cement slurry is then pumped down the
inside of casing 20,
block 104 of Figure 1. As the slurry reaches the bottom of casing 20, it flows
out of casing 20
and into casing annulus 26 between casing 20 and the wall of wellbore 18. As
cement slurry
flows up annulus 26, it displaces any fluid in the wellbore 18. To ensure no
cement remains
inside casing 20, devices called "wipers" may be pumped by a wellbore
servicing fluid (e.g.,
drilling mud) through casing 20 behind the cement. The wiper contacts the
inside surface of
casing 20 and pushes any remaining cement out of casing 20. When cement slurry
reaches the
earth's surface 16, and annulus 26 is filled with slurry, pumping is
terminated and the cement is
allowed to set. The elastomer-coated sensors of the present disclosure may
also be used to
determine one or more parameters during placement and/or curing of the cement
slurry. Also, the
elastomer-coated sensors of the present disclosure may also be used to
determine completion of
the primary cementing operation, as further discussed herein below.
During cementing, or subsequent the setting of cement, a data interrogator
tool 40 may be
positioned in wellbore 18, as described at block 106 of Figure 1. In
embodiments such as that
shown in Figure 2, the interrogator tool 40 may be run downhole via a wireline
or other
conveyance. In alternative embodiments, the wiper may be equipped with a data
interrogator tool
40 and may read data from the elastomer-coated sensors while being pumped
downhole and
transmit same to the surface. In alternative embodiments, an interrogator tool
40 may be run into
the wellbore 18 following completion of cementing a segment of casing, for
example as part of
the drill string during resumed drilling operations. The data interrogator
tool 40 may then be
signaled to interrogate the elastomer-coated sensors (as described at block
108 of Figure 1)
whereby the elastomer-coated sensors are activated to record and/or transmit
data (as described
in block 110 of Figure 1). The data interrogator tool 40 communicates the data
to computer (e.g.,
a processor) whereby data sensor (and likewise cement slurry) position and
cement integrity may
be determined (e.g., calculated as described at block 112 of Figure 1) via
analyzing sensed
parameters for changes, trends, expected values, etc. For example, such data
may reveal
conditions that may be adverse to cement curing. The elastomer-coated sensors
may provide a
temperature profile over the length of the cement sheath, with a uniform
temperature profile
likewise indicating a uniform cure (e.g., produced via heat of hydration of
the cement during
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curing) or a cooler zone might indicate the presence of water that may degrade
the cement during
the transition from slurry to set cement. Alternatively, such data may
indicate a zone of reduced,
minimal, or missing sensors, which would indicate a loss of cement
corresponding to the area
(e.g., a loss/void zone or water influx/washout). Alternatively, such data may
indicate swelling
or expansion of the elastomer in the cement due to, for example, the presence
of a hydrocarbon
in a crack, void, gap, etc. of the cement. Such methods may be available with
various cement
techniques described herein such as conventional or reverse primary cementing.
Due to the high pressure at which the cement is pumped during conventional
primary
cementing (pump down the casing and up the annulus), fluid from the cement
slurry may leak off
into existing low pressure zones traversed by the wellbore 18. This may
adversely affect the
cement, and incur undesirable expense for remedial cementing operations (e.g.,
squeeze
cementing as discussed hereinbelow) to position the cement in the annulus.
Such leak off may be
detected via the present disclosure as described previously. For example, the
elastomer may
expand or compress indicating a change in density of the cement after the
fluid leaks off.
Additionally, conventional circulating cementing may be time-consuming, and
therefore
relatively expensive, because cement is pumped all the way down casing 20 and
back up annulus
26.
One method of avoiding problems associated with conventional primary cementing
is to
employ reverse circulation primary cementing. Reverse circulation cementing is
a term of art
used to describe a method where a cement slurry is pumped down casing annulus
26 instead of
into casing 20. The cement slurry displaces any fluid as it is pumped down
annulus 26. Fluid in
the annulus is forced down annulus 26, into casing 20 (along with any fluid in
the casing), and
then back up to earth's surface 16. When reverse circulation cementing, casing
shoe 22
comprises a valve that is adjusted to allow flow into casing 20 and then
sealed after the
cementing operation is complete. Once slurry is pumped to the bottom of casing
20 and fills
annulus 26, pumping is terminated and the cement is allowed to set in annulus
26. Examples of
reverse cementing applications are disclosed in U.S. Patent Nos. 6,920,929 and
6,244,342, each
of which is incorporated herein by reference in its entirety.
In embodiments of the present disclosure, a sealant comprising elastomer-
coated data
sensors (e.g., a sealant slurry) is pumped down the annulus 26 in reverse
circulation applications,
a data interrogator 40 is located within the wellbore 18 (e.g., by wireline as
shown in Figure 2 or
integrated into the casing shoe) and sealant performance is monitored as
described with respect
to the conventional primary sealing method disclosed hereinabove.
Additionally, the elastomer-
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coated data sensors of the present disclosure may also be used to determine
completion of a
reverse circulation operation, as further discussed hereinbelow.
Secondary cementing within a wellbore (e.g., wellbore 18) may be carried out
subsequent
to primary cementing operations. A common example of secondary cementing is
squeeze
cementing wherein a sealant such as a cement composition is forced under
pressure into one or
more permeable zones within the wellbore to seal such zones. Examples of such
permeable
zones include fissures, cracks, fractures, streaks, flow channels, voids, high
permeability streaks,
annular voids, or combinations thereof. The permeable zones may be present in
the cement
column residing in the annulus, a wall of the conduit in the wellbore, a
microannulus between
the cement column and the subterranean formation, and/or a microarmulus
between the cement
column and the conduit. The sealant (e.g., secondary cement composition) sets
within the
permeable zones, thereby forming a hard mass to plug those zones and prevent
fluid from
passing therethrough (i.e., prevents communication of fluids between the
wellbore and the
formation via the permeable zone). Various procedures that may be followed to
use a sealant
composition in a wellbore are described in U.S. Patent No. 5,346,012, which is
incorporated by
reference herein in its entirety. In various embodiments, a sealant
composition comprising
elastomer-coated sensors is used to repair holes, channels, voids, and
microannuli in casing,
cement sheath, gravel packs, and the like as described in U.S. Patent Nos.
5,121,795; 5,123,487;
and 5,127,473, each of which is incorporated by reference herein in its
entirety.
In embodiments, the method of the present disclosure may be employed in a
secondary
cementing operation. In these embodiments, data sensors are mixed with a
sealant composition
(e.g., a secondary cement slurry) at block 102 of Figure 1 and subsequent or
during positioning
and hardening of the cement, the sensors are interrogated to monitor the
performance of the
secondary cement in an analogous manner to the incorporation and monitoring of
the data
sensors in primary cementing methods disclosed hereinabove. For example, the
elastomer-coated
sensors may be used to verify that the secondary sealant is functioning
properly and/or to
monitor its long-term integrity.
In embodiments, the methods of the present disclosure are utilized for
monitoring
cementitious sealants (e.g., hydraulic cement), non-cementitious (e.g.,
polymer, latex or resin
systems), or combinations thereof comprising one or more elastomer-coated
sensors, which may
be used in primary, secondary, or other sealing applications. For example,
expandable tubulars
such as pipe, pipe string, casing, liner, or the like are often sealed in a
subterranean formation.
The expandable tubular (e.g., casing) is placed in the wellbore, a sealing
composition is placed
into the wellbore, the expandable tubular is expanded, and the sealing
composition is allowed to
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set in the wellbore. For example, after expandable casing is placed
dovsrnhole, a mandrel may be
run through the casing to expand the casing diametrically, with expansions up
to 25% possible.
The expandable tubular may be placed in the wellbore before or after placing
the sealing
composition in the wellbore. The expandable tubular may be expanded before,
during, or after
the set of the sealing composition. When the tubular is expanded during or
after the set of the
sealing composition, resilient compositions will remain competent due to their
elasticity and
compressibility. Additional tubulars may be used to extend the wellbore into
the subterranean
formation below the first tubular as is known to those of skill in the art.
Sealant compositions
and methods of using the compositions with expandable tubulars are disclosed
in U.S. Patent
Nos. 6,722,433 and 7,040,404 and U.S. Patent Pub. No. 2004/0167248, each of
which is
incorporated by reference herein in its entirety. In expandable tubular
embodiments, the sealants
may comprise compressible hydraulic cement compositions and/or non-
cementitious
compositions.
Compressible hydraulic cement compositions (for example, compressible foamed
sealants)
have been developed which remain competent (continue to support and seal the
pipe) when
compressed, and such compositions may comprise sensors coated with an
elastomer. The sealant
composition is placed in the annulus between the wellbore and the pipe or pipe
string, the sealant
composition is allowed to harden into an impermeable mass, and thereafter, the
expandable pipe
or pipe string is expanded whereby the hardened sealant composition is
compressed, as is the
elastomer coating of the sensors within the sealant composition. In
embodiments, the
compressible foamed sealant comprises a hydraulic cement, a rubber latex, a
rubber latex
stabilizer, a gas and a mixture of foaming and foam stabilizing surfactants.
Suitable hydraulic
cements include, but are not limited to, Portland cement and calcium aluminate
cement.
Often, non-cementitious resilient sealants with comparable strength to cement,
but greater
elasticity and compressibility, are required for cementing expandable casing.
In embodiments,
these sealants comprise polymeric sealing compositions, and such polymeric
sealing
compositions may be mixed with elastomer-coated sensors. In an embodiment, the
sealant
comprises a polymer and a metal containing compound. In embodiments, the
polymer comprises
copolymers, terpolymers, and interpolymers. The metal-containing compounds may
comprise
zinc, tin, iron, selenium magnesium, chromium, or cadmium. The compounds may
be in the
form of an oxide, carboxylic acid salt, a complex with dithiocarbamate ligand,
or a complex with
mercaptobenzothiazole ligand. In embodiments, the sealant comprises a mixture
of latex, dithio
carbamate, zinc oxide, and sulfur.
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In embodiments, the methods of the present disclosure comprise adding
elastomer-coated
data sensors to a sealant to be used behind expandable casing to monitor the
integrity of the
sealant upon expansion of the casing and during the service life of the
sealant. In this
embodiment, the sensors may comprise sensors (e.g., MEMS sensors) capable of
measuring one
or more parameters, for example, expansion or swelling of the elastomer,
compression of the
elastomer, the presence of hydrocarbon, moisture, temperature change, or
combinations thereof.
If the sealant develops cracks, the cracks may be detected by expansion or
compression of the
elastomer-coated sensors. Water influx in the crack may be detected via, for
example, moisture
and/or temperature indication. Hydrocarbon influx in the crack may be detected
via, for example,
elastomer swelling and/or temperature indication.
In an embodiment, the elastomer-coated sensors are added to one or more
wellbore
servicing compositions used or placed downhole in drilling or completing a
monodiameter
wellbore as disclosed in U.S. Patent No. 7,066,284 and U.S. Patent Pub. No.
2005/0241855, each
of which is incorporated by reference herein in its entirety. In an
embodiment, the elastomer-
coated sensors are included in a chemical casing composition used in a
monodiameter wellbore.
In another embodiment, the elastomer-coated sensors are included in wellbore
servicing
compositions (e.g., sealants) used to place expandable easing or tubulars in a
monodiameter
wellbore. Examples of chemical casings are disclosed in U.S. Patent Nos.
6,702,044; 6,823,940;
and 6,848,519, each of which is incorporated herein by reference in its
entirety.
In one embodiment, the elastomer-coated sensors are used to gather wellbore
servicing
composition (e.g., sealant) data and monitor the long-term integrity of the
composition (e.g.,
sealant) placed in a wellbore, for example a wellbore for the recovery of
natural resources such
as water or hydrocarbons or an injection well for disposal or storage. In an
embodiment,
data/information gathered and/or derived from the elastomer-coated sensors in
the composition
(e.g., a downhole wellbore sealant) comprises at least a portion of the input
and/or output to into
one or more calculators, simulations, or models used to predict, select,
and/or monitor the
performance of wellbore sealant compositions over the life of a well. Such
models and
simulators may be used to select a composition comprising elastomer-coated
sensors for use in a
wellbore. After placement in the wellbore, the elastomer-coated sensors may
provide data that
can be used to refine, recalibrate, or correct the models and simulators.
Furthermore, the
elastomer-coated sensors can be used to monitor and record the downhole
conditions that the
sealant is subjected to, and sealant performance may be correlated to such
long term data to
provide an indication of problems or the potential for problems in the same or
different
wellbores. In various embodiments, data gathered from elastomer-coated sensors
is used to select
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a sealant composition or otherwise evaluate or monitor such sealants, as
disclosed in U.S. Patent
Nos. 6,697,738; 6,922,637; and 7,133,778, each of which is incorporated by
reference herein in
its entirety.
In an embodiment, the compositions and methodologies of this disclosure are
employed
via an operating environment that generally comprises a wellbore that
penetrates a subterranean
formation for the purpose of recovering hydrocarbons, storing hydrocarbons,
injection of carbon
dioxide, storage of carbon dioxide, disposal of carbon dioxide, and the like,
and the elastomer-
coated sensors may provide information as to a condition and/or location of
the composition
and/or the subterranean formation. For example, the elastomer-coated sensors
may provide
information as to a location, flow path/profile, volume, density, temperature,
pressure, or a
combination thereof of a hydrocarbon (e.g., natural gas stored in a salt dome)
or carbon dioxide
placed in a subterranean formation such that effectiveness of the placement
may be monitored
and evaluated, for example detecting leaks, determining remaining storage
capacity in the
formation, etc. In some embodiments, the compositions of this disclosure are
employed in an
enhanced oil recovery operation wherein a wellbore that penetrates a
subterranean formation
may be subjected to the injection of gases (e.g., carbon dioxide) so as to
improve hydrocarbon
recovery from said wellbore, and the elastomer-coated sensors may provide
information as to a
condition and/or location of the composition and/or the subterranean
formation. For example, the
elastomer-coated sensors may provide information as to a location, flow
path/profile, volume,
density, temperature, pressure, or a combination thereof of carbon dioxide
used in a carbon
dioxide flooding enhanced oil recovery operation in real time such that the
effectiveness of such
operation may be monitored and/or adjusted in real time during performance of
the operation to
improve the result of same.
Referring to Figure 4, a method 200 for selecting a sealant (e.g., a cementing
composition)
for sealing a subterranean zone penetrated by a wellbore according to the
present embodiment
basically comprises determining a group of effective compositions from a group
of compositions
given estimated conditions experienced during the life of the well, and
estimating the risk
parameters for each of the group of effective compositions. In an alternative
embodiment, actual
measured conditions experienced during the life of the well, in addition to or
in lieu of the
estimated conditions, may be used. Such actual measured conditions may be
obtained for =
example via compositions (e.g., sealants) comprising sensors coated with an
elastomer as
described herein. Effectiveness considerations include concerns that the
sealant composition be
stable under downhole conditions of pressure and temperature, resist downhole
chemicals, and
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possess the mechanical properties to withstand stresses from various downhole
operations to
provide zonal isolation for the life of the well.
In step 212, well input data for a particular well is determined. Well input
data includes
routinely measurable or calculable parameters inherent in a well, including
vertical depth of the
well, overburden gradient, pore pressure, maximum and minimum horizontal
stresses, hole size,
casing outer diameter, casing inner diameter, density of drilling fluid,
desired density of sealant
slurry for pumping, density of completion fluid, and top of sealant. As will
be discussed in
greater detail with reference to step 214, the well can be computer modeled.
In modeling, the
stress state in the well at the end of drilling, and before the sealant slurry
is pumped into the
annular space, affects the stress state for the interface boundary between the
rock and the sealant
composition. Thus, the stress state in the rock with the drilling fluid is
evaluated, and properties
of the rock such as Young's modulus, Poisson's ratio, and yield parameters are
used to analyze
the rock stress state. These terms and their methods of determination are well
known to those
skilled in the art. It is understood that well input data will vary between
individual wells. In an
alternative embodiment, well input data includes data that is obtained via
compositions
comprising a sealant and elastomcr- coated sensors as described herein.
In step 214, the well events applicable to the well are determined. For
example, cement
hydration (setting) is a well event. Other well events include pressure
testing, well completions,
hydraulic fracturing, hydrocarbon production, fluid injection, perforation,
subsequent drilling,
formation movement as a result of producing hydrocarbons at high rates from
unconsolidated
formation, and tectonic movement after the sealant composition has been pumped
in place. Well
events include those events that are certain to happen during the life of the
well, such as cement
hydration, and those events that are readily predicted to occur during the
life of the well, given a
particular well's location, rock type, and other factors well known in the
art. In an embodiment,
well events and data associated therewith may be obtained via compositions
comprising a sealant
and elastomer-coated sensors as described herein.
Each well event is associated with a certain type of stress, for example,
cement hydration is
associated with shrinkage, pressure testing is associated with pressure, well
completions,
hydraulic fracturing, and hydrocarbon production are associated with pressure
and temperature,
fluid injection is associated with temperature, formation movement is
associated with load, and
perforation and subsequent drilling are associated with dynamic load. As can
be appreciated,
each type of stress can be characterized by an equation for the stress state
(collectively "well
event stress states"), as described in more detail in U.S. Patent No.
7,133,778 which is
incorporated herein by reference in its entirety.
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In step 216, the well input data, the well event stress states, and the
sealant data are used to
determine the effect of well events on the integrity of the sealant sheath
during the life of the
well for each of the sealant compositions. The sealant compositions that would
be effective for
sealing the subterranean zone and their capacity from its elastic limit are
determined. In an
alternative embodiment, the estimated effects over the life of the well are
compared to and/or
corrected in comparison to corresponding actual data gathered over the life of
the well via
compositions comprising a sealant and elastomer-coated sensors as described
herein. Step 216
concludes by determining which sealant compositions would be effective in
maintaining the
integrity of the resulting cement sheath for the life of the well.
In step 218, parameters for risk of sealant failure for the effective sealant
compositions are
determined. For example, even though a sealant composition is deemed
effective, one sealant
composition may be more effective than another. In one embodiment, the risk
parameters are
calculated as percentages of sealant competency during the determination of
effectiveness in step
216. In an alternative embodiment, the risk parameters are compared to and/or
corrected in
comparison to actual data gathered over the life of the well via compositions
comprising a
sealant and the elastomer-coated sensors as described herein.
Step 218 provides data that allows a user to perform a cost benefit analysis.
Due to the high
cost of remedial operations, it is important that an effective sealant
composition is selected for
the conditions anticipated to be experienced during the life of the well. It
is understood that each
of the sealant compositions has a readily calculable monetary cost. Under
certain conditions,
several sealant compositions may be equally efficacious, yet one may have the
added virtue of
being less expensive. Thus, it should be used to minimize costs. More
commonly, one sealant
composition will be more efficacious, but also more expensive. Accordingly, in
step 220, an
effective sealant composition with acceptable risk parameters is selected
given the desired cost.
Furthermore, the overall results of steps 200-220 can be compared to actual
data that is obtained
via compositions comprising a sealant composition and the elastomer-coated
sensors as
described herein, and such data may be used to modify and/or correct the
inputs and/or outputs to
the various steps 200-220 to improve the accuracy of same.
As discussed above and with reference to Fig. 2, wipers are often utilized
during
conventional primary cementing to force cement slurry out of the casing. The
wiper plug also
serves another purpose: typically, the end of a cementing operation is
signaled when the wiper
plug contacts a restriction (e.g., casing shoe) inside the casing 20 at the
bottom of the string.
When the plug contacts the restriction, a sudden pressure increase at a pump
of wellbore
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servicing system 30 is registered. In this way, it can be determined when the
cement has been
displaced from the casing 20 and fluid flow returning to the surface via
casing annulus 26 stops.
In reverse circulation cementing, it is also necessary to correctly determine
when cement
slurry completely fills the annulus 26. Continuing to pump cement into annulus
26 after cement
has reached the far end of annulus 26 forces cement into the far end of casing
20, which could
incur lost time if cement must be drilled out to continue drilling operations.
The methods disclosed herein may be utilized to determine when cement slurry
has been
appropriately positioned downhole. Furthermore, as discussed hereinbelow, the
methods of the
present disclosure may additionally comprise using a sensor coated with an
elastomer to actuate
a valve or other mechanical means to close and prevent cement from entering
the casing upon
determination of completion of a cementing operation.
The way in which the method of the present disclosure may be used to signal
when cement
is appropriately positioned within annulus 26 will now be described within the
context of a
reverse circulation cementing operation. Figure 3 is a flowchart of a method
for determining
completion of a cementing operation and optionally further actuating a
downhole tool upon
completion (or to initiate completion) of the cementing operation. This
description will reference
the flowchart of Figure 3, as well as the wellbore depiction of Figure 2.
At block 130, a data interrogator tool as described hereinabove is positioned
at the far end
of casing 20. In an embodiment, the data interrogator tool is incorporated
with or adjacent to a
casing shoe positioned at the bottom end of the casing and in communication
with operators at
the surface. At block 132, elastomer-coated sensors are added to a wellbore
servicing fluid (e.g.,
drilling fluid, completion fluid, cement slurry, spacer fluid, displacement
fluid, etc.) to be
pumped into annulus 26. At block 134, cement slurry is pumped into annulus 26.
In an
embodiment, the elastomer-coated sensors may be placed in substantially all of
the cement slurry
pumped into the wellbore. In an alternative embodiment, the elastomer-coated
sensors may be
placed in a leading plug or otherwise placed in an initial portion of the
cement to indicate a
leading edge of the cement slurry. In an embodiment, elastomer-coated sensors
are placed in
leading and trailing plugs to signal the beginning and end of the cement
slurry. While cement is
continuously pumped into annulus 26, at decision 136, the data interrogator
tool is attempting to
detect whether the data sensors are in communicative proximity with the data
interrogator tool.
As long as no data sensors are detected, the pumping of additional cement into
the annulus
continues. When the data interrogator tool detects the sensors at block 138
indicating that the
leading edge of the cement has reached the bottom of the casing, the
interrogator sends a signal
to terminate pumping. The cement in the annulus is allowed to set and form a
substantially
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impermeable mass which physically supports and positions the casing in the
wellbore and bonds
the casing to the walls of the wellbore in block 148.
If the fluid of block 130 is the cement slurry, elastomer-coated (e.g., MEMS-
based) data
sensors are incorporated within the set cement, and parameters of the cement
(e.g., cracks,
temperature, pressure, ion concentration, stress, strain, presence of
hydrocarbon, etc.) can be
monitored during placement and for the duration of the service life of the
cement according to
methods disclosed hereinabove. Alternatively, the elastomer-coated data
sensors may be added
to an interface fluid (e.g., spacer fluid or other fluid plug) introduced into
the annulus prior to
and/or after introduction of cement slurry into the annulus.
The method just described for determination of the completion of a primary
wellbore
cementing operation may further comprise the activation of a downhole tool.
For example, at
block 130, a valve or other tool may be operably associated with a data
interrogator tool at the
far end of the casing. This valve may be contained within float shoe 22, for
example, as
disclosed hereinabove. Again, float shoe 22 may contain an integral data
interrogator tool, or
may otherwise be coupled to a data interrogator tool. For example, the data
interrogator tool may
be positioned between casing 20 and float shoe 22. Following the method
previously described
and blocks 132 to 136, pumping continues as the data interrogator tool detects
the presence or
absence of data sensors in close proximity to the interrogator tool (dependent
upon the specific
method cementing method being employed, e.g., reverse circulation, and the
positioning of the
sensors within the cement flow). Upon detection of a determinative presence or
absence of
sensors in close proximity indicating the termination of the cement slurry,
the data interrogator
tool sends a signal to actuate the tool (e.g., valve) at block 140. At block
142, the valve closes,
sealing the casing and preventing cement from entering the portion of casing
string above the
valve in a reverse cementing operation. At block 144, the closing of the valve
at 142, causes an
increase in back pressure that is detected at the wellbore servicing system
30. At block 146,
pumping is discontinued, and cement is allowed to set in the annulus at block
148. In
embodiments wherein data sensors have been incorporated throughout the cement,
parameters of
the cement (and thus cement integrity) can additionally be monitored during
placement and for
the duration of the service life of the cement according to methods disclosed
hereinabove.
Improved methods of monitoring the condition from placement through the
service
lifetime of the wellbore servicing compositions disclosed herein provide a
number of advantages.
Such methods are capable of detecting changes in parameters in the wellbore
servicing
compositions described herein, such as integrity (e.g., cracks), density,
present or absence of a
fluid (e.g., hydrocarbon or water), moisture content, temperature, pH, and the
concentration of
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ions (e.g., chloride, sodium, and potassium ions). Such methods provide this
data for monitoring
the condition of the wellbore servicing compositions from the initial quality
control period
during mixing and/or placement, through the compositions' useful service life,
and through its
period of deterioration and/or repair. Such methods also provide this data for
monitoring the
condition of compositions during drilling operations, completion operations,
production
operations, or combinations thereof. Such methods are cost efficient and allow
determination of
real-time data using sensors capable of functioning without the need for a
direct power source
(i.e., passive rather than active sensors), such that sensor size be minimal
to maintain sealant
strength and sealant slurry pumpability. The use of elastomer-coated sensors
for determining
wellbore characteristics or parameters may also be utilized in methods of
pricing a well servicing
treatment, selecting a treatment for the well servicing operation, and/or
monitoring a well
servicing treatment during real-time performance thereof, for example, as
described in U.S.
Patent Pub. No. 2006/0047527 Al , which is incorporated by reference herein in
its entirety.
Figure 5A schematically illustrates an embodiment of the wellbore servicing
system 30 of
Figure 2. As can be seen in the embodiment of Figure 5A, the wellbore
servicing system 30 may
comprise surface wellbore operating equipment (e.g., a first mixing tub 150, a
second mixing tub
152, a first actuator 154, a second actuator 156 , a mixing head 160, a first
mixing paddle 162, a
recirculation pump 164, a second mixing paddle 166, a mixture supply pump 168,
a controller
170, flowlines configured to flow the wellbore servicing composition, or
combinations thereof),
one or more interrogators 180, 182, 184, 186, and a wellbore servicing
composition (e.g., a
wellbore servicing fluid comprising a cement slurry (e.g., hydraulic cement
slurry), a non-
cementitious sealant, a drilling fluid, a sealant, a fracturing fluid, a
completion fluid, or
combinations thereof) comprising a plurality of sensors (e.g., MEMS sensors
175, optionally
elastomer-coated). In additional embodiments, the wellbore servicing system 30
may comprise
components such as additional actuators, sensors (height sensor, flow sensor,
weight sensor,
pressure sensor, temperature sensor), and/or other surface operating equipment
known in the art
with the aid of this disclosure.
In embodiments, the system 30 may be located at the surface of a wellsite. In
an
embodiment, the system 30 is suitable, for example, for mixing a wellbore
servicing composition
in support of wellbore servicing operations, such as mixing cement for
cementing casing into a
wellbore. In additional or alternative embodiments, the system 30 is suitable
for other mixing
operations, for example, for mixing fracturing fluid in support of wellbore
servicing operations,
for example, a formation fracturing operation during well completion and/or
production
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enhancement operations (see, e.g., the embodiment of the system of Figure 5A
and the
description below).
The first actuator 154 and the second actuator 156 may be any of valves, screw
feeders,
augers, elevators, and other actuators known to those skilled in the art with
the aid of this
disclosure. The actuators 154 and/or 156 may be modulated by controlling a
position or by
controlling a rotation rate of the actuator 154 and/or 156. For example, if
the actuator 154 and/or
156 is a valve, the valve may be modulated by varying the position of the
valve. In another
example, if the actuator 154 and/or 156 is a screw feeder, the screw feeder
may be modulated by
varying the rotational speed of the screw feeder. In another example, if the
actuator 154 and/or
156 is an elevator, the elevator may be modulated by varying a linear speed of
the elevator. In
embodiments, the first actuator 154 may control the flow of a carrier fluid,
for example water,
into the first mixing tub 150. In embodiments, the second actuator 156 may
control the flow of a
dry material, for example, dry cement, proppants, and/or additive material,
into the first mixing
tub 150. In an embodiment, the carrier fluid and the dry material are flowed
together in the
mixing head 160 and flow out of the mixing head 160 into the first mixing tub
150. In an
alternative embodiment, the mixing head 160 may be omitted from the system 100
and the first
actuator 154 and the second actuator 156 may dispense materials directly into
the first mixing
tub 150. Additionally, in another embodiment, additional actuators (not shown)
may be provided
to control the introduction of other materials (e.g., additives, MEMS sensors)
into the first
mixing tub 150 and/or second mixing tub 152.
Mixing tubs 150 and 152 may comprise a mixer or blender (e.g., a cement slurry
mixer).
Figure 5A shows the system 30 with two mixing tubs 150 and 152. In alternative
embodiments,
the system 30 may comprise one mixing tub 150 (e.g., receiving mixing
materials therein and
flowing a wellbore servicing composition through mixture supply pump 168), or
more than one
mixing tub (e.g., arranged in series and/or parallel). As can be seen in
Figure 5A, the first mixing
tub 150 may be positioned and/or configured to flow the wellbore servicing
composition into the
second mixing tub 152. In an embodiment, the first mixing tub 150 comprises a
weir over which
the wellbore servicing composition overflows from the first mixing tub 150
into the second
mixing tub 152 (indicated by the dotted lines in Figure 5A). In an additional
or alternative
embodiment, the first mixing tub 150 may be configured to flow the wellbore
servicing
composition into the second mixing tub 152 via piping and/or conduits. In an
embodiment, the
first mixing tub 150 may comprise a mixing paddle 162, and the second mixing
tub 152 may
comprise a mixing paddle 166. In additional or alternative embodiments, the
first mixing tub 150
and/or the second mixing tub 152 may comprise another mechanism for mixing
and/or blending
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the wellbore servicing composition. The wellbore servicing composition is
delivered from the
second mixing tub 152 by the mixture supply pump 168, to the wellbore or other
surface
wellbore operating equipment, for example, equipment for cementing a casing in
a wellbore. For
example, the surface wellbore operating equipment may place a cement slurry in
a wellbore in a
subterranean formation by pumping the cement slurry down an inside of a casing
and flowing the
cement slurry out of the casing and into an annulus between the casing and the
subterranean
formation.
In an embodiment, the system 30 comprises a plurality of sensors coupled with
surface
wellbore operating equipment. For example, a flow rate sensor (e.g., a turbine-
type flow rate
meter) may be positioned between the first actuator 154 and the mixing head
160 to sense the
flow rate through the first actuator 154. In another example, one or more
weight sensors (e.g., a
load cell positioned proximate the first mixing tub 150, second mixing tub
152, or both) may
sense a weight of the first mixing tub 150, the second mixing tub 152,
portions thereof, or
combinations thereof. In another example, a height sensor may sense a height
of the wellbore
servicing composition in the second mixing tub 152.
In an embodiment, the wellbore servicing composition comprises one or more
sensors
(e.g., MEMS sensors 175). Figure 5A shows the MEMS sensors 175 may be added to
the
wellbore servicing composition in the second mixing tub 152 in Figure 5A;
however, MEMS
sensors 175 may be added to the wellbore servicing composition at any suitable
point in the
system 30, e.g., in first mixing tub 150, through an actuator (e.g., actuator
154 and/or 156 and/or
other actuator), by manual admixing, or by any other method known to those
skilled in the art
with the aid of this disclosure (e.g., pre-mixing as described in the method
below). In an
embodiment, the sensors (e.g., MEMS sensors 175 optionally comprising an
elastomer coating)
are integrated or coupled with a radio-frequency-identification (RFID) tag. In
an embodiment,
the sensors (e.g., MEMS sensors 175) may comprise from about 0.01 to about 5
weight percent
of the wellbore servicing composition. In an embodiment, the sensors (e.g.,
MEMS sensors 175
are approximately 0.01 mm2 to approximately 10 mm2 in size.
The system 30 may comprise one or more interrogators 180, 182, 184 and 186.
The
positioning of interrogators 180, 182, 184, and 186 is shown by way of
example, and it is
contemplated that various embodiments may have one interrogator or more than
one interrogator
positioned in communicative proximity (e.g., a distance of about 0.1 meter to
about 10 meters)
with one or more of the MEMS sensors. For example, an interrogator of the
wellbore servicing
system 30 may be positioned on, within, about, around, in proximity to, or
combinations thereof
of surface wellbore operating equipment of the wellbore servicing system 30 at
the surface (e.g.,
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surface 16 of Figure 2) of the wellsite. In an embodiment, an interrogator 180
may be attached to
the wall of the wellbore operating equipment (e.g., second mixing tub 152);
additionally or
alternatively, an interrogator 182 may be positioned within the wellbore
operating equipment
(e.g., second mixing tub 152); additionally or alternatively, an interrogator
184 may be
positioned around a wellbore operating equipment (e.g., a flowline connecting
the second mixing
tub 152 and the mixture supply pump 168); additionally or alternatively, an
interrogator 186 may
be positioned within or around a wellbore operating equipment (e.g., a
flowline 158 flowing
from the mixture supply pump 168 to the wellbore). In embodiments, a recycle
line (e.g.,
flowing from flowline 158 or a flowline upstream of mixture supply pump 168)
may be included
in the system 30 such that a non-uniformly mixed composition (additionally or
alternative, a
composition which is not in spec) may be returned to a mixer (e.g., mixing tub
150 and/or
mixing tub 152) for further mixing and/or adjustment.
The placement of interrogator 180 demonstrates that interrogators disclosed
herein may be
positioned on surface wellbore operating equipment near the wellbore servicing
composition
comprising MEMS sensors 175 but not within the composition. The placement of
interrogator
182 demonstrates that interrogators disclosed herein may be positioned on an
interior surface of
a wellbore operating equipment and within the composition. The placement of
interrogator 184
demonstrates that interrogators disclosed herein may be positioned around
(e.g., on an outer
surface) of surface wellbore operating equipment and not within the
composition. The placement
of interrogator 186 demonstrates that interrogators disclosed herein may be
position around (e.g.,
on an outer surface) of surface wellbore operating equipment and within the
composition. Such
configurations are contemplated for the embodiment disclosed in Figure 5A.
The interrogator (e.g., one or more of interrogators 180, 182, 184, 186) of
wellbore
servicing system 30 may be integrated with a radio-frequency (RF) energy
source and the
MEMS sensors 175 may be passively energized via an FT antenna which picks up
energy from
the RF energy source. The RF energy source may comprise a frequency of 125
kHz, 915 MHz,
13.5 MHz, 2.4 GHz, or combinations thereof. In an embodiment, the interrogator
(e.g., one or
more of interrogators 180, 182, 184, 186) may comprise a mobile transceiver
electromagnetically
coupled with the one or more of the MEMS sensors 175.
The interrogator (e.g., one or more of interrogators 180, 182, 184, 186) of
wellbore
servicing system 30 may retrieve data regarding one or more parameters sensed
by the MEMS
sensors 175, for example, a location of one or more of the MEMS sensors 175
(e.g., in the
wellbore servicing composition in the second mixing tub 152 as shown in Figure
5A), a
condition of mixing, a composition component concentration, a density, a
dispersion of the
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sensors (e.g., MEMS sensors) in the wellbore servicing composition at the
surface of the
wellsite, or combinations thereof. In embodiments, the interrogator may
activate and receive data
from one or more sensors (e.g., MEMS sensors 175) in the wellbore servicing
composition at the
surface of the wellsite (e.g., within second mixing tub 152). In Figure 5A, it
can be seen that
MEMS sensors 175 are uniformly dispersed in the wellbore servicing composition
of second
mixing tub 152.
The interrogator (e.g., one or more of interrogators 180, 182, 184, 186) of
wellbore
servicing system 30 may communicate data to a computer (e.g., controller 170)
whereby data
sensor position (e.g., location) may indicate a mixing condition (e.g.,
uniformity of mixing), a
concentration of a component in the wellbore servicing composition, a density
of the wellbore
servicing composition, a dispersion of the sensors (e.g., MEMS sensors) in the
wellbore
servicing composition at the surface of the wellsite, or combinations thereof.
The computer may
analyze sensed parameters for values, changes in value, trends, expected
values, etc. For
example, such data may reveal conditions that may be adverse to a well-mixed
composition (e.g.,
a drilling fluid, a spacer fluid, a sealant (e.g. cement slurry-hydraulic or
non-cementitious ), a
fracturing fluid, a gravel pack fluid, or a completion fluid).
In embodiments, the system 30 may further comprise an access window (e.g., a
window
which comprises a material such as polycarbonate or other material suitable
for use under the
conditions of the wellbore servicing system 30) of surface wellbore operating
equipment which
is coupled with an interrogator (e.g., interrogator 180, 182, 184, and/or
186). The access window
is suitable for facilitating the interrogation of the MEMS sensors within the
surface wellbore
operating equipment.
The controller 170 may be used to control a condition of the wellbore
servicing
composition being mixed in the system 30, e.g., via controlled parameters such
as feed flow rate,
mixing speed, recycle flow rate, supply flow rate, and other conditions known
to those skilled in
the art with the aid of this disclosure. In an embodiment, the controller 170
may be configured to
control at least one of surface wellbore operating equipment of the system 30
to deliver a
wellbore servicing composition having suitable properties at a desired flow
rate, e.g., at any
point in the system 30 such as the output of the mixture supply pump 168. For
example, the
controller 170 may control the first actuator 154, the second actuator 156,
the mixing head 160,
the first mixing paddle 162, the recirculation pump 164, the second mixing
paddle 166, the
mixture supply pump 168, or combinations thereof, to deliver a wellbore
servicing composition
(e.g., a cement slurry) having specified conditions (e.g., uniformly dispersed
MEMS sensors) at a
specified flowrate to a wellbore.
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In embodiments, the controller 170 may receive the sensed parameters and/or
conditions
from the MEMS sensors 175. From these sensed parameters and/or conditions, the
controller 170
may determine a parameter and/or condition of the wellbore servicing
composition in the system
30 (e.g., a density, uniformity of mixing, etc., e.g., based on a location of
one or more of the
MEMS sensors 175) and use control commands to adjust a condition and/or
parameter (e.g., a
location of the MEMS sensors 175, a condition of mixing, a composition
component
concentration, a density, a dispersion of the sensors (e.g., MEMS sensors) in
the wellbore
servicing composition at the surface of the wellsite, or combinations thereof)
of the wellbore
servicing composition, for example, by controlling the surface wellbore
operating equipment
(e.g., the first actuator 154, the second actuator 156 , the mixing head 160,
the first mixing
paddle 162, the recirculation pump 164, the second mixing paddle 166, the
mixture supply pump
168, or combinations thereof).
Figure 5A schematically illustrates another embodiment of the wellbore
servicing system
30 of Figure 2. As shown in the embodiment of Figure 5B, the wellbore
servicing system 30 may
comprise one or more surface wellbore operating equipment (e.g., a composition
treatment
system 210, one or more storage vessels (e.g., storage vessels 310, 312, 314,
and 320), bulk
mixers (e.g., gel blender 240 and sand blender 242), a wellbore services
manifold trailer 250, one
or more high- pressure (HP) pumps 270, one or more flowline 342, 260, 280, 290
or other
flowlines downstream of the first bulk mixer (e.g., gel blender 240), a
conduit leading to the
wellbore (e.g., conduit 190), other surface wellbore operating equipment known
to those of skill
in the art with the aid of this disclosure, or combinations thereof), a
wellbore servicing
composition (e.g., a drilling fluid, a spacer fluid, a sealant (e.g. cement
slurry-hydraulic or non-
cementitious), a fracturing fluid, a gravel pack fluid, a completion fluid, or
combinations thereof)
comprising sensors (e.g., MEMS sensors) located within the surface wellbore
operating
equipment, and one or more interrogators placed in communicative proximity
(e.g., a distance of
about 0.1 meter to about 10 meters) with the sensors. The system 30 may
further comprise an
access window (e.g., a window which comprises a material such as polycarbonate
or other
material suitable for use under the conditions of the wellbore servicing
system 30) of a surface
wellbore operating equipment and coupled with an interrogator (discussed
below). The access
window is suitable for facilitating the interrogation of the MEMS sensors
within the surface
wellbore operating equipment. In Figure 5B, the system 30 may further comprise
a recycle
flowline which recycles a non-conforming wellbore servicing composition
through the wellbore
servicing system 30 so that the composition can be adjusted to conform with a
desired
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characteristic, according to the method described herein below, before placing
the wellbore
servicing composition in a wellbore.
In embodiments, the system 30 of Figure 5A may be located at the surface of a
wellsite. In
an embodiment, the wellbore servicing system 30 of Figure 5A may be configured
to
communicate a mixed wellbore servicing composition into the wellbore (e.g.,
wellbore 18 of
Figure 2) at a rate and/or pressure suitable for the performance of a given
wellbore servicing
operation. For example, in an embodiment where the wellbore servicing system
30 is configured
for the performance of a stimulation operation (e.g., a perforating and/or
fracturing operation),
the wellbore servicing system 30 of Figure 5A may be configured to deliver a
wellbore servicing
composition (e.g., a perforating and/or fracturing fluid) at a rate and/or
pressure sufficient for
initiating, forming, and/or extending a fracture into a hydrocarbon-bearing
formation (e.g.,
subterranean formation 14 of Figure 2 or a portion thereof).
In operation of the system 30, water from the composition treatment system 210
is
introduced, either directly or indirectly (e.g., via treated water vessel
310), into the gel blender
240 and then into the sand blender 242 where the water is mixed with various
other components
and/or additives to form a wellbore servicing composition. The wellbore
servicing composition
is introduced into the wellbore services manifold trailer 250, which is in
fluid communication
with the one or more HP pumps 270, and then introduced into the conduit 190.
The fluid
communication between two or more components of the wellbore servicing system
30 may be
provided by any suitable flowline or conduit.
Persons of ordinary skill in the art with the aid of this disclosure will
appreciate that the
flowlines described herein (e.g., flowlines of Figures 5A and 5B) may include
various
configurations of piping, tubing, etc., that are fluidly connected, for
example, via flanges, collars,
welds, etc. These flowlines may include various configurations of pipe tees,
elbows, and the like.
These flowlines fluidly connect the various surface wellbore operating
equipment described
above.
In an embodiment, the blender 240 may be configured to mix solid and fluid
components
to form wellbore servicing composition. In the embodiment of Figure 5B,
gelling agent from a
storage vessel 312, treated water from intermediate storage vessel 310, and
additives from a
storage vessel 320 may be fed into the blender 240 via flowlines 322, 340 and
350, respectively.
Alternatively, water treated by fluid treatment system 210 may be fed directly
into gel blender
240. In an embodiment, the gel blender 240 may comprise any suitable type
and/or configuration
of blender. For example, the gel blender 240 may be an Advanced Dry Polymer
(ADP) blender
and the additives may be dry blended and dry fed into the gel blender 240. In
an alternative
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embodiment, additives may be pre-blended with water, for example, using a GEL
PRO blender,
which is a commercially available from Halliburton Energy Services, Inc., to
form a liquid gel
concentrate that may be fed into the gel blender 240. In the embodiment of
Figure 5B, fluid from
gel blender 240 and sand/proppant from a storage vessel 314 may be fed into
sand blender 242
via flowlines 342 and 330, respectively. In alternative embodiments, sand or
proppant, water,
.. and/or additives may be premixed and/or stored in a storage tank before
introduction into the
wellbore services manifold trailer 250. In the embodiment of Figure 5A , the
sand blender 242 is
in fluid communication with a wellbore services manifold trailer 250 via a
flowline 260.
In the embodiment of Figure 5A , the wellbore servicing composition may be
introduced
into the wellbore services manifold trailer 250 from the sand blender 242 via
flowline 260. As
.. used herein, the term "wellbore services manifold trailer" may include a
truck and/or trailer
comprising one or more manifolds for receiving, organizing, pressurizing,
and/or distributing
wellbore servicing compositions during wellbore servicing operations.
Alternatively, a wellbore
servicing manifold need not be contained on a trailer, but may comprise any
suitable
configuration. In the embodiment illustrated by Figure 5B, the wellbore
services manifold trailer
.. 250 is coupled to eight high pressure (HP) pumps 270 via outlet flowlines
280 and inlet
flowlines 290. In alternative embodiments, however, any suitable number,
configuration, and/or
type of pumps may be employed in a wellbore servicing operation. The HP pumps
270 may
comprise any suitable type of high-pressure pump, a nonlimiting example of
which is a positive
displacement pump. Outlet flowlines 280 are outlet lines from the wellbore
services manifold
.. trailer 250 that supply fluid to the HP pumps 270. Inlet flowlines 290 are
inlet lines from the HP
pumps 270 that supply fluid to the wellbore services manifold trailer 250. In
an embodiment, the
HP pumps 270 may be configured to pressurize the wellbore servicing
composition to a pressure
suitable for delivery into the wellbore. For example, the HP pumps 270 may be
configured to
increase the pressure of the wellbore servicing composition to a pressure of
about 10,000 psi;
.. alternatively, about 15,000 psi; alternatively, about 20,000 psi or higher.
In an embodiment, the wellbore servicing composition may be reintroduced into
the
wellbore services manifold trailer 250 from the HP pumps 270 via inlet
flowlines 290, for
example, such that the wellbore servicing composition may have a suitable
total fluid flow rate.
One of skill in the art with the aid of this disclosure will appreciate that
one or more of the
surface wellbore servicing equipment, for example, as disclosed herein, may be
sized and/or
provided in a number so as to achieve a suitable pressure and/or flow rate of
the wellbore
servicing composition to the wellbore. For example, the wellbore servicing
composition may be
provided from the wellbore services manifold trailer 250 via flowline 190 to
the wellbore at a
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total flow rate of between about 1 BPM to about 200 BPM, alternatively from
between about 50
BPM to about 150 BPM, alternatively about 100 BPM.
As indicated above, the system 30 of Figure 5A may comprise a wellbore
servicing
composition. In embodiments, the wellbore servicing composition may comprise a
wellbore
servicing fluid (e.g., a hydraulic cement slurry or non-cementitious sealant).
In additional or
alternative embodiments, the wellbore servicing composition may be formulated
as a drilling
fluid, a spacer fluid, a sealant, a fracturing fluid, a gravel pack fluid, a
completion fluid, or
combinations thereof In additional or alternative embodiments, the wellbore
servicing
composition may comprise one or more sensors placed therein. The sensors
(e.g., MEMS
sensors) may be added to the wellbore servicing composition at any point in
the system 30
suitable for adding such sensors. For example, MEMS sensors may be added to
surface wellbore
operating equipment via an actuator of the type described in Figure 5A, by
manual admixing, or
by any other method known to those skilled in the art with the aid of this
disclosure (e.g., pre-
mixing as described in the method below).
In an embodiment, the sensors (e.g., MEMS sensors optionally comprising an
elastomer
coating) are integrated or coupled with a radio-frequency-identification
(RFID) tag. In
embodiments, the sensors contained are ultra-small, e.g., 3mm2 , such that the
sensors are
pumpable in the disclosed wellbore servicing compositions. In embodiments, the
MEMS device
of the sensor may be approximately 0.01 mm2 to 1 mm2 , alternatively 1 mm2 to
3 mm2,
alternatively 3 mm2 to 5 mm2 , or alternatively 5 mm2 to 10 mm2 . In
embodiments, the sensors
may be approximately 0.01 mm2 to 10 mm2. In an embodiment, the composition
comprises an
amount of sensors effective to measure one or more desired parameters. In an
embodiment, the
sensors may be present in the disclosed wellbore servicing compositions in an
amount of from
about 0.001 to about 10 weight percent. Alternatively, the sensors may be
present in the
disclosed wellbore servicing compositions in an amount of from about 0.01 to
about 5 weight
percent.
The wellbore servicing system 30 may further comprise one or more
interrogators which
are placed in a part of the wellbore servicing system 30 as indicated in
Figure 5A by the box 360
having dashed lines (e.g., coupled with one or more of blenders 240, 242, one
or more of
flowlines 342, 260, 280, 290, conduit 190, one or more of HP pumps 270, or
combinations
thereof). An interrogator of the wellbore servicing system 30 may be
positioned on, within,
about, around, in proximity to, or combinations thereof of surface wellbore
operating equipment
of the wellbore servicing system 30 at the surface (e.g., surface 16 of Figure
2) of the wellsite. In
an embodiment, the interrogator is attached to the surface wellbore operating
equipment.
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In embodiments, the interrogator may retrieve data regarding one or more
parameters (e.g.,
a location, a condition of mixing, a composition component concentration, a
density, a dispersion
of the sensors (e.g., MEMS sensors) in the well bore servicing composition at
the surface of the
wellsite, or combinations thereof) sensed by the sensors (e.g., MEMS sensors).
In embodiments,
the interrogator may activate and receive data form one or more sensors (e.g.,
MEMS sensors) in
the wellbore servicing composition at the surface of the wellsite (e.g.,
within surface wellbore
operating equipment). The interrogator of wellbore servicing system 30 may
communicate data
to a computer (e.g., a controller 370) whereby data sensor position (e.g.,
location) may indicate a
mixing condition (e.g., uniformity of mixing), a concentration of a component
in the wellbore
servicing composition, a density of the wellbore servicing composition, a
dispersion of the
sensors (e.g., MEMS sensors) in the wellbore servicing composition at the
surface of the well
site, or combinations thereof.
The interrogator may comprise a transceiver electromagnetically coupled with
the sensors.
In an embodiment, the interrogator is integrated with a radio-frequency (RF)
energy source and
the sensors are passively energized via an FT antenna which picks up energy
from the RF energy
source, and wherein the RF energy source comprises a frequency of 125 kHz, 915
MHz, 13.5
MHz, 2.4 GHz, or combinations thereof.
In an embodiment, the controller 370 may be configured to control at least one
surface
wellbore operating equipment of the system 30 of Figure 5A to deliver a
wellbore servicing
composition having suitable properties at a controlled flow rate, e.g., at any
point in the system
30 such as HP pumps 270. For example, the controller 170 may control the water
treatment
system 210, one or more storage vessels (such as storage vessels 310, 312,
314, and 320), bulk
mixers such as gel blender 240 and sand blender 242, the wellbore services
manifold trailer 250,
one or more high-pressure (HP) pumps 270, or combinations thereof, to deliver
a wellbore
servicing composition (e.g., a fracturing fluid) having specified conditions
at a specified flowrate
to a wellbore, e.g., via conduit 190.
In embodiments, the controller 370 may be used to control a condition of the
wellbore
servicing composition being mixed in the system 30, e.g., via controlled
parameters such as feed
flow rate, mixing speed, recycle flow rate, supply flow rate, and other
conditions known to those
skilled in the art with the aid of this disclosure. The controller 370 may
control the mixing
conditions of the surface wellbore equipment (e.g., gel blender 240, sand
blender 242), including
time period, agitation method, pressure, and temperature of the wellbore
servicing composition
in the bulk mixer, to produce a uniformly-mixed wellbore servicing composition
having a
controlled composition, density, viscosity, or combinations thereof.
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In embodiments, the controller 370 may receive the sensed parameters and/or
conditions
from the MEMS sensors placed within the wellbore servicing composition. From
these sensed
parameters and/or conditions, the controller 370 may determine a parameter
and/or condition of
the wellbore servicing composition in the system 30 (e.g., a density,
uniformity of mixing, a
density, a component concentration, a dispersion of the sensors, e.g., based
on a location of one
or more of the MEMS sensors) and use control commands to adjust a condition
and/or parameter
(e.g., a location of the MEMS sensors) of the wellbore servicing composition,
for example, by
controlling the surface wellbore operating equipment (e.g., composition
treatment system 210,
one or more storage vessels (such as storage vessels 310, 312, 314, and 320),
bulk mixers su.ch
as gel blender 240 and sand blender 242, the wellbore services manifold
trailer 250, one or more
high-pressure (HP) pumps 270, or combinations thereof).
In embodiments, one or more MEMS sensors placed within the wellbore servicing
composition may be assigned a unique identifier. When a MEMS sensor having a
unique
identifier sends data, the data may include the unique identifier alone or in
combination with
other data.
A unique identifier may be used to track a specific MEMS sensor as it travels
through the
wellbore. For example, downhole tools, sensors, antennas, or other devices
capable of receiving
data from a MEMS sensor may be distributed along the wellbore and may receive
data including
a unique identifier from a MEMS sensor travelling through the wellbore. Based
on the location
of the downhole equipment device and the time at which the unique identifier
is received by the
reception device, the general path and velocity of the MEMS sensor may be
determined.
Alternatively or in addition to tracking through devices disposed in the
wellbore, the MEMS
sensor may include a self-locating system and provide data via the self-
locating system that
either directly provides the location of the MEMS sensor or can be used to
calculate the location
of the MEMS sensor. For example, the MEMS sensor may include an inertial
system including
one or more accelerometers and gyroscopes to determine one or more of the MEMS
sensor's
position, velocity, and acceleration. Since the MEMS sensor transmitting the
unique identifier is
part of a wellbore servicing composition, the travel undertaken by the MEMS
sensor may be
used as an indicator of how the fraction of the wellbore servicing composition
containing the
MEMS sensor is travelling through the wellbore.
In addition to the unique identifier, the data sent by the MEMS sensor may
include other
sensor readings. These readings may include, but are not limited to, pressure,
temperature, pH,
electrical conductivity, thermal conductivity, moisture, stress, and strain.
In embodiments, the
additional sensor data may be used with tracking information to determine
downhole conditions
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at points throughout the wellbore. For example, sensor readings for a
particular parameter
obtained from a MEMS sensor being tracked through a wellbore may be used to
generate a
profile of the particular parameter through the wellbore. Sensor readings
collected from
subsequent MEMS sensors passed through the wellbore may be combined with the
first MEMS
sensor data in order to confirm, supplement, or otherwise refine the profile.
In another example,
since the position of MEMS sensors tracked through the wellbore is known,
successive MEMS
sensors passed through the wellbore may be used to periodically monitor
conditions at a specific
point within the wellbore.
In embodiments, MEMS sensors may be active sensors. Active MEMS sensors may
transmit data independently and may eliminate the need for inserting an
interrogator into the
wellbore to activate the MEMS sensor and retrieve data. By actively
transmitting data
independent of interrogation, an active MEMS sensor may be used to collect
data from the
MEMS sensor in real-time and in wellbore locations that may be unreachable by
an interrogator.
An active MEMS sensors may be configured to communicate data to devices in its
proximity. These devices may include, but are not limited to, other active
MEMS sensors,
surface equipment, and downhole equipment. By receiving and retransmitting the
active MEMS
sensor data, the devices may be used to establish a communication network
between the active
MEMS sensor and one or more specific devices. For example, the active MEMS
sensor may
communicate data to a specific piece of surface equipment via any of one or
more MEMS
sensors, one or more pieces of downhole equipment, and one or more pieces of
surface
equipment, whether taken alone or in combination. Communication between
devices may occur
wirelessly or by wired connections and may use any suitable communications
protocol.
An active MEMS sensor may include an on-board power source. The on-board power
source may comprise one or both of an energy storage device and an energy
generating device.
An energy storage device may include, for example, a battery or fuel-cell, and
may store energy
for use by the active MEMS sensor as it passes through the wellbore. In
contrast, an energy
generating device may generate energy as the MEMS sensor passes through the
wellbore.
An energy storage device of an active MEMS sensor may be rechargeable.
Recharging of
the energy storage device may occur at the surface before the active MEMS
sensor is introduced
into the wellbore. Recharging may also occur as the active MEMS sensor passes
through the
wellbore. For example, the energy storage device may be chargeable inductively
and one or
more inductive chargers may be disposed within the wellbore to charge the
energy storage
device when the active MEMS sensor is in proximity to the one or more
inductive chargers. Such
an inductive charger may be installed in the wellbore, for example as part of
a downhole tool
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string, or may be lowered into the wellbore. The active MEMS sensor may also
include both an
energy storage device and an energy generating device such that the energy
storage device is
charged by the energy generating device.
Energy generating devices generally convert one or more of chemical, thermal,
or
mechanical energy into electrical energy for use by the active MEMS sensor,
including for
storage in an energy storage device of the active MEMS sensor. Suitable energy
generating
devices include, but are not limited to, combustors, turbines, heat engines,
photovoltaic cells,
thermoelectric generators, and piezoelectric generators. Accordingly, energy
generating devices
may take advantage of various downhole conditions to generate electrical
energy. For example, a
turbine may be used to generate electricity from fluid flow around or through
the active MEMS
sensor, a thermoelectric generator may be used to generate electricity from
temperature gradients
along the wellbore, and a piezoelectric generator may be used to generate
electricity from
vibrations induced in the active MEMS sensor by fluid flow or equipment
vibrations.
Although one or more of the embodiments disclosed herein may be disclosed with
reference to a cementing operation or stimulation operation, upon viewing this
disclosure one of
skill in the art will appreciate that the wellbore servicing systems and/or
the methods disclosed
herein may be employed in the performance of various other wellbore servicing
operations such
as primary cementing, secondary cementing, or other sealant operation when
stimulation
embodiments are disclosed and such as stimulation operations when cementing
embodiments are
disclosed. As such, unless otherwise noted, although one or more of the
embodiments disclosed
herein may be disclosed with reference to a particular operation, the
disclosure should not be
construed as so-limited.
Figure 6 is a flowchart of an embodiment of a method for using sensors (e.g.,
MEMS
sensors optionally comprising an elastomer coating) at the surface of a
wellsite. At block 600,
sensors are selected based on the parameter(s) or other conditions to be
determined or sensed for
the wellbore servicing composition in surface wellbore operating equipment
(e.g., as described
for Figure 5A and/or Figure 5B) at the surface of a wellsite.
At block 602, a quantity of sensors (e.g., MEMS sensors optionally comprising
an
elastomer coating) is mixed with a wellbore servicing composition (e.g., a
drilling fluid, a spacer
fluid, a sealant (e.g. a wellbore servicing fluid comprising a cement slurry,
hydraulic cement
slurry, or a non-cementitious sealant), a fracturing fluid, a gravel pack
fluid, a completion fluid,
or combinations thereof). In embodiments, the sensors are added to the
wellbore servicing
composition by any methods known to those of skill in the art with the aid of
this disclosure. For
example, for a wellbore servicing composition formulated as a sealant (e.g. a
wellbore servicing
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fluid comprising a cement slurry, hydraulic cement slurry, or a non-
cementitious sealant), the
sensors may be mixed with a dry material, mixed with one more liquid
components (e.g., water
or a non-aqueous fluid), or combinations thereof. The mixing may occur onsite,
for example,
sensors may be added into a surface mixer (e.g., a cement slurry mixer such as
mixing tubs 150
and/or 152 of Figure 5A, a gel blender 240 of Figure 5B, a sand blender 242 of
Figure 5A), a
conduit or other flowline at the surface of the wellsite, or combinations
thereof. The sensors may
be added directly to the mixer, may be added to one or more flowlines and
subsequently fed to
the mixer, may be added downstream of the mixer, or combinations thereof. In
embodiments,
sensors are added after a blending unit and slurry pump, for example, through
a lateral by-pass.
The sensors may be metered in and mixed at the wellsite, or may be pre-mixed
into the wellbore
servicing composition (or one or more components thereof) and subsequently
transported to the
wellsite. For example, the sensors may be dry mixed with dry cement and
transported to the
wellsite where a cement slurry is formed comprising the sensors. Alternatively
or additionally,
the sensors may be pre- mixed with one or more liquid components (e.g., mix
water) and
transported to the wellsite where a wellbore servicing composition is formed
comprising the
sensors. The properties of the wellbore composition or components thereof may
be such that the
sensors distributed or dispersed therein do not substantially settle or
stratify during transport
and/or placement.
At block 604, an interrogator of the wellbore servicing system 30, (e.g., an
interrogator as
described above for Figures 5A and/or 5B) interrogates the sensors in the
wellbore servicing
composition. The interrogator may be placed in communicative proximity (e.g.,
a distance of
about 0,1 meter to about 10 meters) of one or more of the sensors. In an
embodiment, the
interrogator is attached to surface wellbore operating equipment. In
embodiments, the
interrogator may retrieve data regarding one or more parameters (e.g., a
location, a condition of
mixing, a density, a composition component concentration) sensed by the
sensors (e.g., MEMS
sensors). In embodiments, the interrogator may activate and receive data form
one or more
sensors (e.g., MEMS sensors) in the wellbore servicing composition at the
surface of the wellsite
(e.g., within surface wellbore operating equipment). The interrogator may
communicate data to a
computer (e.g., a controller 170 of Figure SA or a controller 370 of Figure
SA) whereby data
sensor position (e.g., location) may indicate a mixing condition (e.g.,
uniformity of mixing), a
concentration of a component in the wellbore servicing composition, a density
of the wellbore
servicing composition, a dispersion of the sensors (e.g., MEMS sensors) in the
wellbore
servicing composition at the surface of the wellsite, or combinations thereof.
The interrogator
may comprise a mobile transceiver electromagnetically coupled with the
sensors.
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At block 606, the sensors (e.g., MEMS sensors) are activated to receive and/or
transmit
data via the signal from the interrogator. The interrogator activates and
receives data from the
sensors (e.g., by sending out an RF signal) while the wellbore servicing
composition mixes and
flows through the wellbore servicing system 30. Activation of the sensors may
be accomplished
by the techniques described hereinabove or known in the art with the aid of
this disclosure. The
interrogator receives data sensed by the sensors in the wellbore servicing
composition, for
example, while being mixed, while flowing from one surface wellbore operating
equipment to
another, while flowing through conduit 190 during placement into the wellbore,
or combinations
thereof. The data sensed by the sensors may comprise a location of the sensors
within the
wellbore servicing composition, a condition of mixing, a density, a
concentration of a component
(e.g., of the wellbore servicing composition), a dispersion of the sensors
(e.g., MEMS sensors) in
the wellbore servicing composition at the surface of the wellsite, or
combinations thereof. In
embodiments of a method, the interrogator may be integrated with a radio-
frequency (RF)
energy source and the sensors may be passively energized via an FT antenna
which picks up
energy from the RF energy source, and the RF energy source may comprise
frequencies of 125
kHz, 915 MHz, 13.5 MHz, 2.4 GHz, or combinations thereof. In an embodiment of
a method,
the sensors may comprise a radio frequency identification (RFID) tag.
At block 608, the interrogator communicates the data to one or more computer
components
(e.g., memory and/or microprocessor), for example, located within the
interrogator at the surface
or otherwise associated with the interrogator (e.g., via wired or wireless
communication with a
computer (e.g., controller 170 of Figure 5A, controller 370 of Figure 5B)
configured to control
the interrogator and to determine a parameter of the wellbore servicing
composition). The data
may be used locally or remotely from the interrogator to determine a
parameter, (e.g., a location
of each sensor in a wellbore servicing composition (e.g., MEMS sensor
optionally comprising an
elastomer coating), a dispersion of the sensors (e.g., MEMS sensors) in the
wellbore servicing
composition, a temperature, a pressure, a swelling or expansion of an
elastomer coating of the
MEMS sensor in response to contact with a hydrocarbon or water), and correlate
the determined
parameter(s) to evaluate a mixing condition (e.g., the sensor locations, a
concentration of a
component, a density, a dispersion of the sensors (e.g., MEMS sensors) in the
wellbore servicing
composition at the surface of the wellsite, or combinations thereof of the
wellbore servicing
composition (e.g., a drilling fluid, a spacer fluid, a sealant (e.g. cement
slurry), a fracturing fluid,
a gravel pack fluid, a completion fluid, or combinations thereof) and/or the
sensors therein. If the
determined parameter(s) indicate the wellbore servicing composition comprises
suitable mixing
(e.g., the sensors are adequately dispersed in the wellbore servicing
composition), suitable
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concentrations, suitable density, etc., which makes the composition suitable
for use in the
wellbore, then the wellbore servicing composition may be suitable for
placement in a wellbore
(e.g., pumping via conduit 190 of Figure 5A or pumping via flowline 158 of
Figure 5A). If the
determined parameter(s) indicate the wellbore servicing composition is not
suitable for use in the
wellbore, the disclosed method and system allow a correction (e.g., an
adjustment) of the
wellbore servicing composition before placement into the wellbore. For
example, parameters
including a component concentration of the wellbore servicing composition, a
condition of
surface wellbore operating equipment (e.g., a mixing condition of a bulk mixer
of the wellbore
servicing system 30), a uniformity of mixing (e.g., as indicated by the
location of one or more of
sensors (e.g., a dispersion) in the wellbore servicing composition), a density
(e.g., of a
component of the wellbore servicing composition and/or the wellbore servicing
composition), or
combinations thereof, may be adjusted at the surface of the wellsite (e.g.,
recycling a non-
conforming composition back to a mixer, e.g., mixing tubs 150 and/or 152 of
Figure 5A or
blenders 240 and/or 242 of Figure 5A) before placing the wellbore servicing
composition into a
wellbore.
The method steps of blocks 604, 606, and 608 may be repeated until a parameter
of the
wellbore servicing composition is suitable for placing the wellbore servicing
composition in a
wellbore (e.g., pumping via conduit 190 of Figure 5A or pumping via flowline
158 of Figure
5A). As such, real-time monitoring of a parameter of the wellbore servicing
composition
comprising the sensors (e.g., MEMS sensors optionally comprising an elastomer
coating) at the
surface of a wellsite may be used to control the design (e.g., uniformly mix)
of the wellbore
servicing composition for use in the wellbore.
At block 610, the wellbore servicing composition (e.g., a drilling fluid, a
spacer fluid, a
sealant (e.g. a wellbore servicing fluid comprising a cement slurry, hydraulic
cement slurry, or a
non-cementitious sealant), a fracturing fluid, a gravel pack fluid, or a
completion fluid)
comprising the sensors is then pumped into the wellbore (e.g., pumping via
conduit 190 of
Figure 5A or pumping via flowline 158 of Figure 5A). The composition may be
placed
downhole as part of a wellbore operation such as stimulating, primary
cementing, secondary
cementing, or other sealant operation as described in herein. The sensors of
the wellbore
servicing composition may be interrogated in conduit 190 (e.g., at portions of
the conduit 190 of
Figure 5A or flowline 158 of Figure 5A at the surface of the wellsite, at
portions of the conduit
190 of Figure 5B or flowline 158 of Figure 5A below the surface, or both), and
during placement
of the composition in the wellbore, as described hereinabove. In an
embodiment, the wellbore
servicing composition comprises a wellbore servicing fluid which comprises a
hydraulic cement
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slurry or a non-cementitious sealant, and additionally, the cement slurry may
be placed in a
wellbore (e.g., pumping via conduit 190 of Figure 5A or pumping via flowline
158 of Figure 5A)
in a subterranean formation, wherein the cement slurry is pumped down an
inside of a casing and
flows out of the casing and into an annulus between the casing and the
subterranean formation.
The exemplary wellbore servicing compositions disclosed herein may directly or
indirectly
affect one or more components or pieces of equipment associated with the
preparation, delivery,
recapture, recycling, reuse, and/or disposal of the disclosed wellbore
servicing compositions. For
example, the disclosed wellbore servicing compositions may directly or
indirectly affect one or
more mixers, related mixing equipment, mud pits, storage facilities or units,
composition
separators, heat exchangers, sensors, gauges, pumps, compressors, and the like
used generate,
store, monitor, regulate, and/or recondition the exemplary wellbore servicing
compositions. The
disclosed wellbore servicing compositions may also directly or indirectly
affect any transport or
delivery equipment used to convey the wellbore servicing compositions to a
wellsite or
downhole such as, for example, any transport vessels, conduits, pipelines,
trucks, tubulars, and/or
pipes used to compositionally move the wellbore servicing compositions from
one location to
another, any pumps, compressors, or motors (e.g., topside or downhole) used to
drive the
wellbore servicing compositions into motion, any valves or related joints used
to regulate the
pressure or flow rate of the wellbore servicing compositions, and any sensors
(i.e., pressure and
temperature), gauges, and/or combinations thereof, and the like. The disclosed
wellbore
servicing compositions may also directly or indirectly affect the various
downhole equipment
and tools that may come into contact with the cement compositions/additives
such as, but not
limited to, wellbore casing, wellbore liner, completion string, insert
strings, drill string, coiled
tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole
motors and/or pumps,
cement pumps, surface- mounted motors and/or pumps, centralizers, turbolizers,
scratchers,
floats (e.g., shoes, collars, valves, etc.), logging tools and related
telemetry equipment, actuators
(e.g., electromechanical devices, hydromechanical devices, etc.), sliding
sleeves, production
sleeves, plugs, screens, filters, flow control devices (e.g., inflow control
devices, autonomous
inflow control devices, outflow control devices, etc.), couplings (e.g.,
electro-hydraulic wet
connect, dry connect, inductive coupler, etc.), control lines (e.g.,
electrical, fiber optic, hydraulic,
etc.), surveillance lines, drill bits and reamers, sensors or distributed
sensors, downhole heat
exchangers, valves and corresponding actuation devices, tool seals, packers,
cement plugs,
bridge plugs, and other wellbore isolation devices, or components, and the
like.
The wellbore servicing compositions (e.g., a cementitious or a non-
cementitious resilient
sealant, as discussed above) and MEMS sensors also include various advantages.
For example,
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for embodiments comprising an elastomer coating, the elastomer coating of the
sensors can
protect and maintain the integrity of the sensors in the wellbore servicing
composition due to the
resilient nature of elastomers while also functioning as a part of the sensor
(e.g., expanding,
swelling, or compressing to indicate a change in one or more of the parameters
disclosed
hereinabove). Moreover, a composition can optionally have one or two
mechanisms of
resilience: i) resilience in the elastomer coating of the elastomer-coated
sensors, and optionally,
ii) resilience in the wellbore servicing composition itself (e.g., a foamed
and/or polymeric
sealing composition). Additionally, the use of non-silicon based sensors as
described
hereinabove allows for the use of MEMS sensors in thicker compositions and/or
in scenarios
where the distance between a communication tool (e.g., the interrogator
disclosed herein) and the
MEMS sensors is such that other sensor types may not be able to communicate
information.
While various embodiments of the methods have been shown and described,
modifications
thereof can be made by one skilled in the art without departing from the
spirit and teachings of
the present disclosure. The embodiments described herein are exemplary only,
and are not
intended to be limiting. Many variations and modifications of the methods
disclosed herein are
possible and are within the scope of this disclosure. Where numerical ranges
or limitations are
expressly stated, such express ranges or limitations should be understood to
include iterative
ranges or limitations of like magnitude falling within the expressly stated
ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10
includes 0.11, 0.12, 0.13,
etc.). Use of the term "optionally" with respect to any element of a claim is
intended to mean that
the subject element is required, or alternatively, is not required. Both
alternatives are intended to
be within the scope of the claim. Use of broader terms such as comprises,
includes, having, etc.
should be understood to provide support for narrower terms such as consisting
of, consisting
essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out
above but is
only limited by the claims which follow, that scope including all equivalents
of the subject
matter of the claims. Each and every claim is incorporated into the
specification as an
embodiment of the present disclosure. Thus, the claims are a further
description and are an
addition to the embodiments of the present disclosure. The discussion of a
reference herein is not
an admission that it is prior art to the present disclosure, especially any
reference that may have a
publication date after the priority date of this application. The disclosures
of all patents, patent
applications, and publications cited herein are hereby incorporated by
reference, to the extent
that they provide exemplary, procedural or other details supplementary to
those set forth herein.
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