Note: Descriptions are shown in the official language in which they were submitted.
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SURFACE WELLBORE OPERATING EQUIPMENT UTILIZING MEMS SENSORS
BACKGROUND OF THE INVENTION
[0001] 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.
[0002] 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
(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.
[0003] 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
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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.
[0004] 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
[0005] Disclosed herein is a method comprising mixing a wellbore servicing
composition
comprising Micro-Electro-Mechanical System (MEMS) sensors in surface wellbore
operating
equipment at the surface of a wellsite.
[0006] 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.
[0007] Further disclosed herein is a method comprising placing a wellbore
servicing
composition comprising a Micro-Electro-Mechanical System (MEMS) sensor in 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
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compression or swelling of the elastomer, an expansion of the elastomer, or a
change in density
of the composition.
[0008] 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 subtenanean formation, and using the MEMS
sensor to detect a
location of the wellbore servicing composition, wherein the sensor is coated
with an elastomer.
[0009] Also disclosed herein is a method comprising placing a Micro-Electro-
Mechanical
System (MEMS) sensor in a wellbore and/or subtenanean 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.
[0010] 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.
[0011] 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.
[0012] 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.
[0013] 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.
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[0014] Further disclosed herein is a method comprising placing a wellbore
servicing
composition comprising a plurality of elastomer-coated sensors in a wellbore,
a subterranean
form ati on , or both.
[0015] Further disclosed herein is a wellbore servicing composition comprising
a base fluid and
a plurality of elastomer-coated sensors.
[0016] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] For a detailed description of the disclosed embodiments of the present
disclosure,
reference will now be made to the accompanying drawing in which:
[0018] Figure 1 is a flowchart illustrating an embodiment of a method in
accordance with the
present disclosure.
[0019] Figure 2 is a schematic of a typical onshore oil or gas drilling rig
and wellbore.
[0020] 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.
[0021] Figure 4 is a flowchart of a method for selecting between a group of
sealant compositions
according to one embodiment of the present disclosure.
[0022] Figure 5A is a schematic view of an embodiment of a wellbore servicing
system
according to the disclosure.
[0023] Figure 5B is a schematic view of another embodiment of a wellbore
servicing system
according to the disclosure.
[0024] Figure 6 is a flowchart illustrating an embodiment of a method
according to the
disclosure.
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DETAILED DESCRIPTION
[0025] 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.
[0026] Embodiments of methods include detecting and/or monitoring the position
and/or
condition of wellbore servicing compositions and/or the wellbore/surrounding
formation using data
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sensors comprising Micro-Electro-Mechanical System (MEMS) sensors. Embodiments
of
methods include detecting and/or monitoring the position and/or condition of
wellbore servicing
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.
[0027] 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
'nixing, 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.
[0028] 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-
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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 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 5B), a sand blender (as depicted in Figure 5B), 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.
[0029] The wellbore servicing composition (e.g., a sealant sluiTy 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
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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 sensor and
correlate the measured
parameter(s) to such locations to evaluate performance of the wellbore
servicing composition (e.g.,
sealant).
[0030] 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.
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[00311 In embodiments, the wellbore servicing composition nriay 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. Sealants may be utilized in
setting
expandable casing, which is further described hereinbelow. In other
embodiments, the sealant
is a cement utilized for primary or secondary wellbore cementing operations,
as discussed
further hereinbelow.
[0032] 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. 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.
[0033] 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.
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[00341 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 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).
100351 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, 13, C, G, and I I 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. 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.
[0036] In additional or alternative embodiments, the wellbore servicing
composition may be
formulated as a drilling fluid comprising elastomer-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
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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
filtercake (e.g., disposed
therein) and may provide information as to a condition (e.g., thickness)
and/or location of the
filtercake. 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.
[0037] 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
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.)
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and/or location of the fracture. For example, the elastomer-coated sensors may
provide
information useful for ascertaining the fracture complexity.
[0038] 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 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 canier 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.
[0039] 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
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operations. In embodiments, the elastomer-coated sensors may provide
information regarding the
location, position, integrity, flow, etc. of the spacer fluid.
[0040] 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.
[0041] 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-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.
[0042] 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
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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.
[0043] 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.
[0044] 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 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 (1/psi) to
about 1.5x10-9
(1/psi), where "isothermal compressibility factor" is defined as a change in
volume with pressure,
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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).
[0045] 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. In
additional or
alternative embodiments, the elastomer may comprise a WeIlLifeCD material,
which is an
elastomeric material commercially available from Halliburton.
[0046] 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
pressurcs 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.
[0047] 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
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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 scnsors, 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.
[0048] 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.
[0049] 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 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.
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[0050] 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.
[0051] In embodiments, the sensors coated with an elastomer 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 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.,
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sulfur, carbon dioxide, hydrogen sulfide, etc. present in hydrocarbon gas or
liquid), or a
combination thereof.
[0052] 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.
[0053] 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.
[0054] 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 0.01mm2 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
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embodiment, the elastomer-coated sensors may be present in the disclosed
wellborc 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.
[0055] 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.
[0056] 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.
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 Bl.
[0057] 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
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(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
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.
[0058] 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.
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[0059] 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
signals. The data intetTogator 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.
[0060] 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.
[0061] In embodiments, the data inteiTogator 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
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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 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.
[0062] 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 10m, 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 lm to 5m.
Alternatively, close proximity
comprises a distance of from 5m 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
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and close proximity comprises 0.5m to lm. Alternatively, the transceiver
interrogates the sensor
with RF energy at 2.4 GHz and close proximity comprises lm to 2m.
[0063] 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
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).
[0064] 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.
[0065] 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
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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 sluiTy 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 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.
[0066] 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
slun-y 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.
[0067] 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
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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 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.
[0068] 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.
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[0069] 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.
[0070] 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-coated data sensors of the present disclosure may
also be used to
determine completion of a reverse circulation operation, as further discussed
hereinbelow.
[0071] 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
thc wellbore, a
microannulus between the cement column and the subterranean formation, and/or
a
microannulus 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. In various
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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.
[0072] 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.
[0073] 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 set in the wellbore. For example, after expandable
casing is placed
downhole, 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 thc
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. In expandable tubular embodiments, the sealants
may
comprise compressible hydraulic cement compositions and/or non-cementitious
compositions.
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[0074] 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.
[0075] 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.
[0076] 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.
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[0077] In an embodiment, the clastomer-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.
In an embodiment, the elastomer-coated sensors are included in a chemical
casing
composition used in a monodiametcr wellbore. In another embodiment, the
elastomer-coated
sensors are included in wellbore servicing compositions (e.g., sealants) used
to place
expandable casing 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.
[0078] 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 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.
[0079] 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
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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.
[0080] 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 possess the
mechanical properties to withstand stresses from various downhole operations
to provide zonal
isolation for the life of the well.
[0081] 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
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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
dctcrmination 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 elastomer-coated sensors as
described herein.
[0082] 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.
[0083] 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.
[0084] 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
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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.
[0085] 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.
[0086] 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.
[0087] 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 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.
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[0088] 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.
[0089] The methods disclosed herein may be utilized to determine when cement
sluiTy 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.
[0090] 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.
[0091] 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
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in the annulus is allowed to set and form a substantially 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.
[0092] 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.
[0093] 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.
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[0094] 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 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.
[0095] 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, flow lines 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 clastomer-coatcd). 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.
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[0096] 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 enhancement
operations (see, e.g., the embodiment of the system of Figure 5B and the
description below).
[0097] 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.
[0098] 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
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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 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.
[0099] 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.
[00100] 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
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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.
[00101] The system 30 may comprise one or more interrogators 180, 182, 184 and
186. The
positioning of intenogators 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., 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.
[00102] 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 5B.
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[00103] 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.
[00104] 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 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.
[00105] 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).
[00106] 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
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suitable for facilitating the interrogation of the MEMS sensors within the
surface wellbore operating
equipment.
[00107] 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.2., uniformly dispersed MEMS sensors) at a specified
flowrate to a wellbore.
[00108] 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 rnixing, 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).
[00109] Figure 5B 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),
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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 characteristic, according to the method described
herein below, before
placing the wellbore servicing composition in a wellbore.
[00110] In embodiments, the system 30 of Figure 5B may be located at the
surface of a wellsite.
In an embodiment, the wellbore servicing system 30 of Figure 5B 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 5B 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).
[00111] 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
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communication between two or more components of the wellbore servicing system
30 may be
provided by any suitable flowline or conduit.
[00112] 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.
[00113] 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
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 5B, the sand
blender 242 is in fluid
communication with a wellbore services manifold trailer 250 via a flowline
260.
[00114] In the embodiment of Figure 5B, 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
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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.
[00115] 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
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.
[00116] As indicated above, the system 30 of Figure 5B 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
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those skilled in the art with the aid of this disclosure (e.g., pre-mixing as
described in the method
below).
[00117] In an embodiment, the sensors (e.g., MEMS sensors optionally
comprising an elastomer
coating) are integrated or coupled with a radio-frequency-identification (RFD)
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 0.0 lmm2 to 1 mm2, alternatively 1 mm2 to 3 mm2,
alternatively 3
mm 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.
[00118] 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 5B 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.
[00119] 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 wellbore 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,
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a dispersion of the sensors (e.g., MEMS sensors) in the wellbore servicing
composition at the
surface of the wellsite, or combinations thereof.
[00120] 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.
[00121] In an embodiment, the controller 370 may be configured to control at
least one surface
wellbore operating equipment of the system 30 of Figure 5B 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.
[00122] 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.
[00123] 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
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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 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).
[00124] 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.
[00125] 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.
[00126] 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
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
5B), a conduit or other
flowline at the surface of the wellsite, or combinations thereof. The sensors
may be added directly
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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.
[00127] 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 5A or a controller 370 of Figure 5B) 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 intenogator may comprise
a mobile
transceiver electromagnetically coupled with the sensors.
[00128] 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
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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.
[00129] 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
paratneter, (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 concentrations, suitable density, etc., which makes the composition
suitable for use in the
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wellbore, then the wellbore servicing composition may be suitable for
placement in a wellbore
(e.g., pumping via conduit 190 of Figure 5B or pumping via flowline 158 of
Figure SA). 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 5B)
before placing the wellbore servicing composition into a wellbore.
[00130] 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 5B 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.
[00131] 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 5B 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 5B
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
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wellbore servicing fluid which comprises a hydraulic cement 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 5B 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 subtenanean formation.
[00132] 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
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actuation devices, tool seals, packers, cement plugs, bridge plugs, and other
wellbore
isolation devices, or components, and the like.
[00133] 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, 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.
[00134] 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.
[00135] Accordingly. the scope of protection is not limited by the description
set out above
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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.
[00136] The following are additional enumerated embodiments according to the
present
disclosure:
[00137] Embodiment 1 is a method comprising mixing a wellbore servicing
composition
comprising a plurality of Micro-Electro-Mechanical System (MEMS) sensors in
surface
wellbore operating equipment at the surface of a wellsite.
1001381 Embodiment 2 is the method of embodiment 1, further comprising
retrieving data
regarding one or more parameters sensed by the plurality of MEMS sensors,
wherein the one
or more parameters comprises a location of the plurality of MEMS sensors
within the
wellbore servicing composition, a condition of mixing, a concentration of a
componcnt, a
density, or combinations thereof
[00139] Embodiment 3 is the method of one of embodiments 1 to 2, wherein the
wellbore
servicing composition comprises wellbore servicing fluid, wherein the wellbore
servicing
fluid is a hydraulic cement slurry or a non-cementitious sealant.
1001401 Embodiment 4 is the method of embodiment 3, further comprising placing
the
cement slurry in a wellbore 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.
1001411 Embodiment 5 is the method of embodiment 1 wherein the wellbore
servicing
composition is formulated as a drilling fluid, a sealant, a fracturing fluid,
a completion fluid,
or a combination thereof, wherein the plurality of MEMS scnsors comprises an
amount from
about 0.01 to about 5 weight percent of the wellbore composition.
[00142] Embodiment 6 is the method of one of embodiments 1 to 5, further
comprising
placing an interrogator in communicative proximity with onc 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
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sensors, and wherein the interrogator comprises a mobile transceiver
electromagnetically coupled
with the one or more of the plurality of MEMS sensors.
[00143] Embodiment 7 is the method of one of embodiments 1 to 6, further
comprising adjusting
a location of one or more of the plurality of the MEMS sensors in the wellbore
servicing
composition at the surface of the wellsite before placing the wellbore
servicing composition into a
wellbore.
[00144] Embodiment 8 is the method of one of embodiments 1 to 7, wherein one
or more of the
plurality of MEMS sensors is integrated or coupled with a radio-frequency
identification (RFID)
tag.
[00145] Embodiment 9 is the method of one of embodiments 1 to 8, further
comprising adjusting
a condition of the surface wellbore operating equipment at the surface of the
wellsite before
placing the wellbore servicing composition into a wellbore.
[00146] Embodiment 10 is the method of one of embodiments 6 to 9, wherein the
interrogator is
attached to the surface wellbore operating equipment at the surface of the
wellsite.
[00147] Embodiment 11 is the method of one of embodiments 1 to 10, wherein the
communicative proximity comprises a distance of about 0.1 meter to about 10
meters.
[00148] Embodiment 12 is the method of one of embodiments 6 to 11, wherein the
interrogator is
integrated with a radio-frequency (RF) energy source and the plurality of MEMS
sensors are
passively energized via an FT antenna which picks up energy from the RF energy
source, and
wherein the RF energy source comprises frequencies of 125 kHz, 915 MHz, 13.5
MHz, 2.4 GHz,
or combinations thereof.
[00149] Embodiment 13 is the method of one of embodiments 1 to 12, wherein the
plurality of
MEMS sensors are approximately 0.01 mm2 to approximately 10 mm2 in size.
[00150] Embodiment 14 is the method of one of embodiments 1 to 13, further
comprising
determining a dispersion of the MEMS sensors in the wellbore servicing
composition at the surface
of the wellsite.
[00151] Embodiment 15 is 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
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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.
[00152] Embodiment 16 is the system of embodiment 1 5, wherein the plurality
of MEMS sensors
comprises an elastomer coating, wherein the elastomer coating of the plurality
of elastomer-coated
MEMS sensors comprises 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.
[00153] Embodiment 17 is the system of one of embodiments 15 to 16, wherein
the surface
wellbore operating equipment comprises a cement blender, a proppant mixer, a
gel blender, a sand
blender, a flowline, a conduit, or combinations thereof.
[00154] Embodiment 18 is the system of one of embodiments 15 to 17, wherein
the interrogator is
positioned in, on, around, about, in proximity to, or combinations thereof,
the surface wellbore
operating equipment at the surface of the wellsite.
[00155] Embodiment 19 is the system of one of embodiments 15 to 18, wherein
the interrogator
comprises a mobile transceiver electromagnetically coupled with the one or
more of the plurality of
MEMS sensors.
[00156] Embodiment 20 is the system of one of embodiments 15 to 19, wherein
the interrogator is
integrated with a radio-frequency (RF) energy source and the plurality of MEMS
sensors are
passively energized via an FT antenna which picks up energy from the RF energy
source, and
wherein the RF energy source comprises frequencies of 125 kHz, 915 MHz, 13.5
MHz, 2.4 GHz,
or combinations thereof.
[00157] Embodiment 21 is the system of one of embodiments 15 to 20, wherein
the wellbore
servicing composition is formulated as a drilling fluid, a spacer fluid, a
sealant, a fracturing fluid, a
gravel pack fluid, or a completion fluid.
[00158] Embodiment 22 is the system of one of embodiments 15 to 21, wherein a
dispersion of
the MEMS sensors in the wellbore servicing composition is determined at the
surface of the
wellsite.
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