U.S. patent application number 14/784146 was filed with the patent office on 2016-10-27 for mems-lost circulation materials for evaluating fluid loss and wellbore strengthening during a drilling operation.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES INC.. Invention is credited to Clinton Cheramie Galliano, Walter Varney Andrew Graves, Matthew Dennis Rowe.
Application Number | 20160312551 14/784146 |
Document ID | / |
Family ID | 54784133 |
Filed Date | 2016-10-27 |
United States Patent
Application |
20160312551 |
Kind Code |
A1 |
Rowe; Matthew Dennis ; et
al. |
October 27, 2016 |
MEMS-LOST CIRCULATION MATERIALS FOR EVALUATING FLUID LOSS AND
WELLBORE STRENGTHENING DURING A DRILLING OPERATION
Abstract
Micro-electro-mechanical systems lost circulation materials
(MEMS-LCMs) of various sizes, shapes, and specific gravities may be
used in a drilling fluid to determine the preferred LCMs for use in
wellbore strengthening of the wellbore. For example, a method may
include drilling at least a portion of a wellbore penetrating a
subterranean formation with a drilling fluid that comprises a base
fluid, a plurality of MEMS-LCMs, and a plurality of LCMs, wherein
the MEMS-LCMs and the LCMs are substantially similar in size,
shape, and specific gravity; measuring a first concentration of the
MEMS-LCMs in the drilling fluid before circulating the drilling
fluid through the wellbore; measuring a second concentration of the
MEMS-LCMs in the drilling fluid after circulating the drilling
fluid through the wellbore; performing a comparison of the first
and second concentrations of the MEMS-LCMs; and changing a
composition of the drilling fluid based on the comparison.
Inventors: |
Rowe; Matthew Dennis;
(Lafayette, LA) ; Galliano; Clinton Cheramie;
(Houma, LA) ; Graves; Walter Varney Andrew;
(Lafayette, LA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES INC. |
Houston |
TX |
US |
|
|
Family ID: |
54784133 |
Appl. No.: |
14/784146 |
Filed: |
December 30, 2014 |
PCT Filed: |
December 30, 2014 |
PCT NO: |
PCT/US2014/072663 |
371 Date: |
October 13, 2015 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 33/138 20130101;
C09K 8/03 20130101; E21B 21/08 20130101; E21B 21/003 20130101; E21B
47/11 20200501; E21B 47/00 20130101; E21B 7/00 20130101; E21B 33/03
20130101; E21B 21/062 20130101 |
International
Class: |
E21B 21/08 20060101
E21B021/08; C09K 8/03 20060101 C09K008/03; E21B 47/00 20060101
E21B047/00; E21B 7/00 20060101 E21B007/00; E21B 21/00 20060101
E21B021/00; E21B 21/06 20060101 E21B021/06 |
Claims
1. A method comprising: drilling at least a portion of a wellbore
penetrating a subterranean formation with a drilling fluid that
comprises a base fluid, a plurality of micro-electro-mechanical
systems lost circulation materials (MEMS-LCMs), and a plurality of
lost circulation materials (LCMs), wherein the MEMS-LCMs and the
LCMs are substantially similar in size, shape, and specific
gravity; measuring a first concentration of the MEMS-LCMs in the
drilling fluid before circulating the drilling fluid through the
wellbore; measuring a second concentration of the MEMS-LCMs in the
drilling fluid after circulating the drilling fluid through the
wellbore; performing a comparison of the first and second
concentrations of the MEMS-LCMs; and changing a composition of the
drilling fluid based on the comparison.
2. The method of claim 1 further comprising: measuring a third
concentration of the MEMS-LCMs in the drilling fluid while the
drilling fluid is circulating through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, and
third concentrations of MEMS-LCMs.
3. The method of claim 1, wherein changing the composition of the
drilling fluid involves increasing the concentration of the
LCMs.
4. The method of claim 1, wherein the LCMs are first LCMs, and
wherein changing the composition of the drilling fluid involves
adding a plurality of second LCMs to the drilling fluid.
5. The method of claim 4, wherein the second LCMs have a larger
diameter than the first LCMs.
6. The method of claim 4, wherein the second LCMs have a greater
specific gravity than the first LCMs.
7. The method of claim 1, wherein the LCMs are first LCMs and the
MEMS-LCMs are first MEMS-LCMs, the drilling fluid further
comprising a plurality of second LCMs and a plurality of second
MEMS-LCMs, wherein the second MEMS-LCMs and the second LCMs are
substantially similar in size, shape, and specific gravity, and
wherein the first MEMS-LCMs and the second MEMS-LCMs exhibit
different signatures readable by a micro-electro-mechanical systems
(MEMS) sensor, the method further comprising: measuring a first
concentration of the second MEMS-LCMs in the drilling fluid before
circulating the drilling fluid through the wellbore; measuring a
second concentration of the second MEMS-LCMs in the drilling fluid
after circulating the drilling fluid through the wellbore;
performing a second comparison of the first and second
concentrations of the second MEMS-LCMs; and changing the
composition of the drilling fluid based on the comparison and the
second comparison.
8. The method of claim 1, wherein the plurality of the MEMS-LCMs
comprise a passive radio frequency identification device
(RFID).
9. A method comprising: drilling at least a portion of a wellbore
penetrating a subterranean formation with a drilling fluid that
comprises a base fluid, a plurality of micro-electro-mechanical
systems lost circulation materials (MEMS-LCMs), and a plurality of
lost circulation materials (LCMs), wherein the MEMS-LCMs and the
LCMs are substantially similar in size, shape, and specific
gravity; measuring a first concentration and a second concentration
of the MEMS-LCMs in the drilling fluid at a first location and a
second location in the wellbore; performing a comparison of the
first and second concentrations of the MEMS-LCMs; and changing a
composition of the drilling fluid based on the comparison.
10. The method of claim 9 further comprising: measuring a third
concentration of the MEMS-LCMs in the drilling fluid before
circulating the drilling fluid through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, and
third concentrations of MEMS-LCMs.
11. The method of claim 9 further comprising: measuring a third
concentration of the MEMS-LCMs in the drilling fluid after
circulating the drilling fluid through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, and
third concentrations of MEMS-LCMs.
12. The method of claim 9 further comprising: measuring a third
concentration of the MEMS-LCMs in the drilling fluid before
circulating the drilling fluid through the wellbore; measuring a
fourth concentration of the MEMS-LCMs in the drilling fluid after
circulating the drilling fluid through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, third,
and fourth concentrations of MEMS-LCMs.
13. The method of claim 9, wherein changing the composition of the
drilling fluid involves increasing the concentration of the
LCMs.
14. The method of claim 9, wherein the LCMs are first LCMs, and
wherein changing the composition of the drilling fluid involves
adding a plurality of second LCMs to the drilling fluid.
15. The method of claim 9, wherein the LCMs are first LCMs and the
MEMS-LCMs are first MEMS-LCMs, the drilling fluid further
comprising a plurality of second LCMs and a plurality of second
MEMS-LCMs, wherein the second MEMS-LCMs and the second LCMs are
substantially similar in size, shape, and specific gravity, and
wherein the first MEMS-LCMs and the second MEMS-LCMs exhibit
different signatures readable by a micro-electro-mechanical systems
(MEMS) sensor, the method further comprising: measuring a first
concentration and a second concentration of the second MEMS-LCMs in
the drilling fluid at the first location and the second location in
the wellbore; performing a second comparison of the first and
second concentrations of the second MEMS-LCMs; and changing the
composition of the drilling fluid based on the comparison and the
second comparison.
16. The method of claim 9, wherein the plurality of the MEMS-LCMs
comprise a passive radio frequency identification device
(RFID).
17. A system comprising: a drilling assembly with a drill string
extending therefrom, through a blowout preventer (BOP) and a
wellhead and into a wellbore penetrating a subterranean formation;
a wireline extending from the drilling assembly and into the
wellbore; a pump fluidly coupled to the drill string, the drill
string containing a drilling fluid that comprises a base fluid, a
plurality of micro-electro-mechanical systems lost circulation
materials (MEMS-LCMs), and a plurality of lost circulation
materials (LCMs), wherein the MEMS-LCMs and the LCMs are
substantially similar in size, shape, and specific gravity; and at
least one micro-electro-mechanical systems (MEMS) sensor in at
least one location selected from the group consisting of (1) along
the drill string; (2) along a feed pipe fluidly coupled to the
drill string upstream of the wellbore; (3) along a flow line
fluidly coupled to the drill string downstream of the wellbore; (4)
at the wellhead, (5) at the pump, (6) at the BOP, (7) along the
casing, and (8) along the wireline.
18. The system of claim 17, wherein the at least one MEMS sensor is
an active radio frequency identification device (RFID) reader and
the plurality of the MEMS-LCMs comprise a passive RFID.
Description
BACKGROUND
[0001] The present disclosure relates to wellbore strengthening and
fluid loss control.
[0002] Lost circulation is one of the larger contributors to
non-productive time in a wellbore drilling operation. Lost
circulation arises from drilling fluid leaking into the formation
via undesired flow paths (e.g., permeable sections, natural
fractures, and induced fractures). Lost circulation treatments or
pills may be used to remediate the wellbore by plugging the
fractures before drilling can resume.
[0003] Generally, drilling is performed with an overbalance
pressure such that the wellbore pressure is maintained within the
mud weight window (i.e., the area between the pore pressure and the
fracture pressure), FIG. 1. The term "overbalance pressure," as
used herein, refers to the amount of pressure in the wellbore that
exceeds the pore pressure. The term "pore pressure," as used
herein, refers to the pressure of fluids in the formation.
Overbalance pressure is needed to prevent reservoir fluids from
entering the wellbore. The term "fracture pressure," as used
herein, refers to a pressure threshold where pressures exerted from
the wellbore onto the formation in excess of the pressure threshold
cause one or more fractures in the subterranean formation. Wider
mud weight windows allow for drilling with a reduced risk of lost
circulation.
[0004] In traditional subterranean formations, the mud weight
window may be wide, FIG. 1. However, in formations having
problematic zones (e.g., depleted zones, high-permeability zones,
highly tectonic areas with high in-situ stresses, or pressurized
shale zones below salt layers), the mud weight window may be
narrower and more variable, FIG. 2. When the overbalance pressure
exceeds the fracture pressure, a fracture may be induced and lost
circulation may occur. By incorporating a lost circulation material
(LCM) in the fracture to temporarily plug the fracture, the
compressive tangential stress in the near-wellbore region of the
subterranean formation increases, which translates to an increase
in the fracture pressure, thereby widening the mud weight window,
FIG. 3.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] The following figures are included to illustrate certain
aspects of the embodiments, and should not be viewed as exclusive
embodiments. The subject matter disclosed is capable of
considerable modifications, alterations, combinations, and
equivalents in form and function, as will occur to those skilled in
the art and having the benefit of this disclosure.
[0006] FIG. 1 provides an illustrative diagram of an exemplary
wellbore drilling assembly suitable for implementing
micro-electro-mechanical systems (MEMS) LCMs to analyze wellbore
strengthening and lost circulation according to at least some
embodiments described herein.
[0007] FIG. 2 provides an illustrative diagram of an exemplary
wellbore drilling assembly suitable for implementing MEMS-LCMs to
analyze wellbore strengthening and lost circulation according to at
least some embodiments described herein.
[0008] FIG. 3 provides an illustrative diagram of an exemplary
wellbore drilling assembly suitable for implementing MEMS-LCMs to
analyze wellbore strengthening and lost circulation according to at
least some embodiments described herein.
[0009] FIG. 4 provides an illustrative diagram of an exemplary
wellbore drilling assembly suitable for implementing MEMS-LCMs to
analyze wellbore strengthening and lost circulation according to at
least some embodiments described herein.
DETAILED DESCRIPTION
[0010] The present disclosure relates to wellbore strengthening and
fluid loss control and, more specifically, determining a size
distribution of LCM suitable for use in strengthening a wellbore.
The methods described herein utilize micro-electro-mechanical
systems (MEMS) LCMs of various size, shapes, and specific gravities
in a drilling fluid. The MEMS-LCMs may then become incorporated
into fractures as would traditional LCMs. Identification of the
size, shape, and/or specific gravity of the MEMS-LCMs that become
incorporated in the fractures may, then, be used to determine the
preferred LCMs for use in wellbore strengthening of the
wellbore.
[0011] As used herein, the term "MEMS-LCMs" refers to materials
that are or mimic lost circulation materials that have incorporated
therewith at least one MEMS. Generally, the methods described
herein utilize a plurality of different MEMS-LCMs that vary by
size, shape, specific gravity, or a combination thereof. Each type
of MEMS-LCMs (i.e., each MEMS with a specific size, shape, and
specific gravity) may have a unique identifying signature (e.g., a
signal emitted or a passive tag). This identifying signature may
then be detected in order to determine or monitor the presence,
absence, or concentration of each type of MEMS-LCMs.
[0012] FIG. 1 provides an illustrative diagram of an exemplary
wellbore drilling assembly 100 suitable for implementing MEMS-LCMs
to analyze wellbore strengthening and lost circulation according to
at least some embodiments described herein. It should be noted that
while FIG. 1 generally depicts a land-based drilling assembly,
those skilled in the art will readily recognize that the principles
described herein are equally applicable to subsea drilling
operations that employ floating or sea-based platforms and rigs,
without departing from the scope of the disclosure.
[0013] As illustrated, the drilling assembly 100 may include a
drilling platform 102 that supports a derrick 104 having a
traveling block 106 for raising and lowering a drill string 108.
The drill string 108 may include, but is not limited to, drill pipe
and coiled tubing, as generally known to those skilled in the art.
A kelly 110 supports the drill string 108 as it is lowered through
a rotary table 112. A drill bit 114 is attached to the distal end
of the drill string 108 and is driven either by a downhole motor
and/or via rotation of the drill string 108 from the well surface.
As the bit 114 rotates, it creates a wellbore 116 that penetrates
various subterranean formations 118.
[0014] A pump 120 (e.g., a mud pump) circulates a drilling fluid
122 (e.g., comprising a base fluid, MEMS-LCMs, and optionally LCMs)
through a feed pipe 124 and to the kelly 110, which conveys the
drilling fluid 122 downhole through the interior of the drill
string 108 and through one or more orifices in the drill bit 114.
The drilling fluid 122 is then circulated back to the surface via
an annulus 126 defined between the drill string 108 and the walls
of the wellbore 116. At the surface, the recirculated or spent
drilling fluid 122 exits the annulus 126 and may be conveyed to one
or more fluid processing unit(s) 128 via an interconnecting flow
line 130. After passing through the fluid processing unit(s) 128, a
"cleaned" drilling fluid 122 is deposited into a nearby retention
pit 132 (i.e., a mud pit). While illustrated as being arranged at
the outlet of the wellbore 116 via the annulus 126, those skilled
in the art will readily appreciate that the fluid processing
unit(s) 128 may be arranged at any other location in the drilling
assembly 100 to facilitate its proper function, without departing
from the scope of the disclosure.
[0015] One or more of the disclosed MEMS-LCMs and optional LCMs may
be added to the drilling fluid 122 via a mixing hopper 134
communicably coupled to or otherwise in fluid communication with
the retention pit 132. The mixing hopper 134 may include, but is
not limited to, mixers and related mixing equipment known to those
skilled in the art. In other embodiments, however, the MEMS-LCMs
and optional LCMs may be added to the drilling fluid 122 at any
other location in the drilling assembly 100. In at least one
embodiment, for example, there could be more than one retention pit
132, such as multiple retention pits 132 in series. Moreover, the
retention pit 132 may be representative of one or more fluid
storage facilities and/or units where the MEMS-LCMs and optional
LCMs may be stored, reconditioned, and/or regulated until added to
the drilling fluid 122.
[0016] As the drilling fluid 122 circulates through the wellbore,
at least some of the MEMS-LCMs, depending on their characteristics
(e.g., size, shape, and specific gravity), may flow into the
subterranean formation 118 (i.e., lost circulation). Additionally,
at least some of the MEMS-LCMs may become incorporated in fracture
plugs that provide for wellbore strengthening. Further, at least
some of the MEMS-LCMs may stay within the drilling fluid 122 and
return to the surface.
[0017] In some instances, the amount and type of MEMS-LCMS lost
from the drilling fluid due to lost circulation and wellbore
strengthening may be determined by analyzing and comparing the
concentration of each type of MEMS-LCMS in the drilling fluid 122
before introduction into the wellbore and after exiting the
wellbore. For example, MEMS detectors 136,138 (described further
herein) may be included along the drilling fluid flow path of the
drilling assembly 100 at, for example, the feed pipe 124 and the
flow line 130, respectively.
[0018] In some instances, when a plurality of different types of
MEMS-LCMs are used in the drilling fluid 122 that vary by size,
density, and shape, a distribution profile of each variable may be
extrapolated for the MEMS-LCM before and after introduction into
the wellbore 116. Then, the before and after distribution profiles
for each variable may be compared to independently identify sizes,
densities, and shapes that decrease in concentration after
circulation through the wellbore. LCMs may be added or increased in
concentration in the drilling fluid 122 that have or are similar to
all three of the independently identified properties.
[0019] Referring now to FIG. 2, with continued reference to FIG. 1,
illustrated is an exemplary wellbore drilling assembly 200 suitable
for implementing MEMS-LCMs to analyze wellbore strengthening and
lost circulation according to at least some embodiments described
herein. The wellbore drilling assembly 200 is similar to that of
the wellbore drilling assembly 100 of FIG. 1 with identical
reference numbers to indicate the same structures or components
described in reference to FIG. 1. However, the wellbore drilling
assembly 200 includes a measurement while drilling (MWD) tool 140
coupled to the drill string 108. The MWD tool 140 may include MEMS
sensors to detect the MEMS-LCMs downhole. Because the MWD tool 140
is downhole, the concentration and the type of MEMS-LCMs may be
correlated to a downhole location or wellbore depth (e.g., the
distance from the wellhead as measured along the wellbore 116).
[0020] In some instances, when the concentration of a MEMS-LCM at a
location along the wellbore is detected to be higher than it should
be in the drilling fluid 122, it may indicate that the MEMS-LCM is
becoming incorporated in fractures along the wellbore and providing
wellbore strengthening. Accordingly, the concentration of a
commensurate LCM (i.e., having a substantially similar size, shape,
and specific gravity) in the drilling fluid 122 may be increased to
provide additional LCMs of suitable size to provide for wellbore
strengthening. As used herein, the terms "substantially the same,"
"substantially similar," and other grammatical variations thereof
refer to being within about 10% of a given value. For example, an
LCM with a specific gravity of about 2.0 has substantially the same
specific gravity as another LCM with a specific gravity of about
2.2.
[0021] In some instances, the concentration analysis of a MEMS-LCM
in the drilling fluid 122 before introduction into the wellbore 116
and after return to the surface (e.g., using MEMS sensors 136,138,
respectively) may indicate that the MEMS-LCM is being removed from
the drilling fluid 122 (i.e., the concentration decreases).
However, the measurements from a MEMS detector of the MWD-tool 140
may indicate that the MEMS-LCM is not accumulating in a
near-wellbore location. This scenario may indicate that the
MEMS-LCM is being lost to the formation (i.e., in the lost
circulation portion of the drilling fluid). Further, this may
indicate that the characteristics of the MEMS-LCM are insufficient
to plug the fracture and mitigate or eliminate lost circulation.
Accordingly, the concentration of a different LCM may be added to
the drilling fluid 122 to mitigate lost circulation. In some
instance, the LCM added to the drilling fluid 122 may be larger in
size, more spherical in shape, greater in specific gravity, or a
combination thereof. Without being limited by theory it is believed
that such changes in size, shape, specific gravity, or a
combination thereof may enhance plugging of the fractures that the
MEMS-LCMs traverse during lost circulation into the formation
118.
[0022] Referring now to FIG. 3, with continued reference to FIGS. 1
and 2, illustrated is an exemplary wellbore drilling assembly 300
suitable for implementing MEMS-LCMs to analyze wellbore
strengthening and lost circulation according to at least some
embodiments described herein. The wellbore drilling assembly 300 is
similar to that of the wellbore drilling assemblies 100,200 of
FIGS. 1 and 2, respectively, with identical reference numbers to
indicate the same structures or components described in reference
to FIGS. 1 and 2. However, the wellbore drilling assembly 300
includes a plurality of MEMS sensors 142 coupled to and arranged
along the drill string 108. Coupling of the MEMS sensors 142 may be
achieved by, for example, mechanical fasteners, brazing or welding
techniques, adhesives, magnets, the like, and combinations thereof.
In some instances, a housing may be used to contain a MEMS sensor
142 and designed to withstand the pressures that may be experienced
in the wellbore 116.
[0023] The MEMS sensors 142 may be utilized in methods similar to
those described relative to the MWD-tool. However, the plurality of
MEMS sensors 142 disposed coupled to the drill string 108 of the
wellbore drilling assembly 300 may allow for analyzing the
concentration of the MEMS-LCM at multiple locations along the
wellbore 116. Additionally, having a plurality of MEMS sensors 142
disposed along the drill string (e.g., about one MEMS sensor 142
per every 1-5 pipe sections of the drill string 108) may allow for
less movement of the drill string 108 along the wellbore 116 when
identifying lost circulation zones.
[0024] While the MEMS sensors 136,138 are illustrated at the
surface before and after the drilling fluid 122 are circulated
through the wellbore 116, respectively, in some instances, one or
both of the MEMS sensors 136,138 may be excluded from the drilling
assembly 300.
[0025] Referring now to FIG. 4, with continued reference to FIGS.
1-3, illustrated is an exemplary wellbore drilling assembly 400
suitable for implementing MEMS-LCMs to analyze wellbore
strengthening and lost circulation according to at least some
embodiments described herein. The wellbore drilling assembly 400 is
similar to that of the wellbore drilling assemblies 100,200,300 of
FIGS. 1-3, respectively, with identical reference numbers to
indicate the same structures or components described in reference
to FIGS. 1-3. However, the wellbore drilling assembly 400 includes
a wellhead 164 where the wellbore 116 meets the surface. A blowout
preventer (BOP) 160 is coupled to the wellhead 164 where the drill
string 108 passes through the BOP 160 and the wellhead 164 before
entering the wellbore 116. The drilling assembly 400 also includes
a wireline 166 that is run through the BOP 160 and the wellhead 164
and extends into the wellbore 116. As illustrated, the wireline 166
is coupled to the drill string 108 near the drill bit 114, which
may be useful in transmitting power or communicating with the drill
bit 114 (or alternatively could be coupled to a MWD tool 140
illustrated in FIG. 2). MEMS sensors 144,150 may be coupled to the
BOP 144 and the wellhead 164, respectively. This configuration may
be used to analyze MEMS-LCM loss to other parts of the well
including, for example, due to cuttings bed buildup. Similar to the
MEMS sensors 142 coupled to the drill string 108 in FIG. 3, a
plurality of MEMS sensors 154 may be coupled to the wireline 166
for detecting MEMS-LCMs along the wellbore.
[0026] In the drilling assembly 400, a portion of the wellbore 116
has a casing 162. In some instances, MEMS sensors 146 may be
coupled to the casing 162. Similar to the MEMS sensors 142 coupled
to the drill string 108 in FIG. 3, a plurality of MEMS sensors 146
may be coupled to the casing 162.
[0027] As illustrated in FIGS. 1-4, MEMS sensors 136-152 may be
included at a variety of locations along the path the drilling
fluid 122 flows in a drilling assembly 100-400, which includes
combinations of locations not explicitly illustrated. In general,
MEMS sensors may be included at the wellhead 164, the pump 120, the
BOP 160, the casing 162, the wireline 166, or a combination
thereof, including combinations with the previously described MEMS
sensor locations. Further, in subsea drilling assemblies, MEMS
sensors may be coupled to a riser or a slip joint.
[0028] The drilling fluids 122 describe herein may comprise a base
fluid, a plurality of MEMS-LCMs, and optionally LCMs.
[0029] Base fluids suitable for use in conjunction with the
drilling fluid described herein may be oil-based fluids,
aqueous-based fluids, aqueous-miscible fluids, water-in-oil
emulsions, or oil-in-water emulsions. Suitable oil-based fluids may
include alkanes, olefins, aromatic organic compounds, cyclic
alkanes, paraffins, diesel fluids, mineral oils, desulfurized
hydrogenated kerosenes, and any combination thereof. Suitable
aqueous-based fluids may include fresh water, saltwater (e.g.,
water containing one or more salts dissolved therein), brine (e.g.,
saturated salt water), seawater, and any combination thereof.
Suitable aqueous-miscible fluids may include, but not be limited
to, alcohols (e.g., methanol, ethanol, n-propanol, isopropanol,
n-butanol, sec-butanol, isobutanol, and t-butanol), glycerins,
glycols (e.g., polyglycols, propylene glycol, and ethylene glycol),
polyglycol amines, polyols, any derivative thereof, any in
combination with salts (e.g., sodium chloride, calcium chloride,
calcium bromide, zinc bromide, potassium carbonate, sodium formate,
potassium formate, cesium formate, sodium acetate, potassium
acetate, calcium acetate, ammonium acetate, ammonium chloride,
ammonium bromide, sodium nitrate, potassium nitrate, ammonium
nitrate, ammonium sulfate, calcium nitrate, sodium carbonate,
potassium carbonate, and any combination thereof), any in
combination with an aqueous-based fluid, and any combination
thereof. Suitable water-in-oil emulsions, also known as invert
emulsions, may have an oil-to-water ratio from a lower limit of
greater than about 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or
80:20 to an upper limit of less than about 100:0, 95:5, 90:10,
85:15, 80:20, 75:25, 70:30, or 65:35 by volume in the base
treatment fluid, where the amount may range from any lower limit to
any upper limit and encompass any subset therebetween. Examples of
suitable invert emulsions include those disclosed in U.S. Pat. No.
5,905,061, U.S. Pat. No. 5,977,031, and U.S. Pat. No. 6,828,279. It
should be noted that for water-in-oil and oil-in-water emulsions,
any mixture of the above may be used including the water phase
being or including an aqueous-miscible fluid.
[0030] When included, the LCMs may be included in a drilling fluid
122 described herein at about 0.25 pound per barrel (PPB) to about
150 PPB in the drilling fluid, including any subset
therebetween.
[0031] Examples of LCMs may include, but are not limited to, sand,
shale, ground marble, bauxite, ceramic materials, glass materials,
metal pellets, high strength synthetic fibers, resilient graphitic
carbon, cellulose flakes, wood, resins, polymer materials
(crosslinked or otherwise), polytetrafluoroethylene materials, nut
shell pieces, cured resinous particulates comprising nut shell
pieces, seed shell pieces, cured resinous particulates comprising
seed shell pieces, fruit pit pieces, cured resinous particulates
comprising fruit pit pieces, composite materials, fibers of
cellulose (e.g., viscose cellulosic fibers, oil coated cellulosic
fibers, and fibers derived from a plant product like paper fibers),
carbon including carbon fibers, melt-processed inorganic fibers
(e.g., basalt fibers, woolastonite fibers, non-amorphous metallic
fibers, metal oxide fibers, mixed metal oxide fibers, ceramic
fibers, and glass fibers), polymeric fibers (e.g., polypropylene
fibers and poly(acrylic nitrile) fibers), metal oxide fibers, mixed
metal oxide fibers, and the like, and any combination thereof.
Suitable composite materials may comprise a binder and a filler
material wherein suitable filler materials include silica, alumina,
fumed carbon, carbon black, graphite, mica, titanium dioxide,
meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly
ash, hollow glass microspheres, solid glass, and any combination
thereof.
[0032] In some embodiments, LCMs may include a degradable material.
Nonlimiting examples of suitable degradable materials may include,
but are not limited to, degradable polymers (crosslinked or
otherwise), dehydrated compounds, and/or mixtures of the two. As
used herein, the term "degradable" and all of its grammatical
variants (e.g., "degrade," "degradation," "degrading," and the
like) refer to the dissolution or chemical conversion of materials
into smaller components, intermediates, or end products by at least
one of solubilization, hydrolytic degradation, biologically formed
entities (e.g., by bacteria or enzymes), chemical reactions,
electrochemical processes, thermal reactions, or reactions induced
by radiation. In some instances, the degradation of the material
may be sufficient for the mechanical properties of the material to
reduce to a point that the material no longer maintains its
integrity and, in essence, falls apart. The conditions for
degradation are generally wellbore conditions where an external
stimuli may be used to initiate or effect the rate of degradation.
For example, the pH of the fluid that interacts with the material
may be changed by introduction of an acid or a base. The term
"wellbore environment" includes both naturally occurring wellbore
environments and introduced materials into the wellbore.
[0033] Specific examples of LCMs may include, but not be limited
to, BARACARB.RTM. particulates (ground marble, available from
Halliburton Energy Services, Inc., e.g., BARACARB.RTM. 5,
BARACARB.RTM. 25, BARACARB.RTM. 150, BARACARB.RTM. 600,
BARACARB.RTM. 1200), STEELSEAL.RTM. particulates (resilient
graphitic carbon, available from Halliburton Energy Services, Inc.,
e.g., STEELSEAL.RTM. powder, STEELSEAL.RTM. 50, STEELSEAL.RTM. 150,
STEELSEAL.RTM. 400 and STEELSEAL.RTM. 1000), WALL-NUT particulates
(ground walnut shells, available from Halliburton Energy Services,
Inc., e.g., WALL-NUT.RTM. M, WALL-NUT.RTM. coarse, WALL-NUT.RTM.
medium, and WALL-NUT.RTM. fine), BARAPLUG.RTM. (sized salt water,
available from Halliburton Energy Services, Inc., e.g., including
BARAPLUG.RTM. 20, BARAPLUG.RTM. 50, and BARAPLUG.RTM. 3/300);
BARAFLAKE.RTM. (calcium carbonate and polymers, available from
Halliburton Energy Services, Inc.), carbon fibers derived from
poly(acrylonitrile) (also referred to as PAN fibers), PANEX fibers
(carbon fibers, available from Zoltek, e.g., PANEX.RTM. 32,
PANEX.RTM. 35-0.125'', and PANEX.RTM. 35-0.25''), PANOX (oxidized
PAN fibers, available from SGL Group), rayon fibers including
BDF.TM. 456 (rayon fibers, available from Halliburton Energy
Services, Inc.), poly(lactide) ("PLA") fibers, alumina fibers,
cellulosic fibers, BAROFIBRE.RTM. fibers (cellulosic fiber,
available from Halliburton Energy Services, Inc., e.g., including
BAROFIBRE.RTM. and BAROFIBRE.RTM. C), and the like, and any
combination thereof.
[0034] The MEMS portion of the MEMS-LCMs described herein may, in
some instances, be passive radio frequency identification devices
(RFIDs). RFIDs combine a microchip with an antenna (the RFID chip
and the antenna are collectively referred to as the "transponder"
or the "tag"). The antenna provides the RFID chip with power when
exposed to a narrow band, high frequency electromagnetic field from
a transceiver. A dipole antenna or a coil, depending on the
operating frequency, connected to the RFID chip, powers the
transponder when current is induced in the antenna by an RF signal
from the transceiver's antenna. Such a device can return a unique
identification "ID" number by modulating and re-radiating the radio
frequency (RF) wave.
[0035] Given the wellbore environment and volume of MEMS-LCMS that
may be utilized in the various methods, passive RFIDs may be
particularly useful in the methods described herein due to their
ability to function without a battery, as well as, their low cost,
indefinite life, simplicity, efficiency, and identification
capabilities at a distance without contact (tether-free information
transmission ability). Each of the employed MEMS-LCM types may have
antennas that respond to RF waves of different frequencies, so as
to uniquely identify each type of MEMS-LCM. 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.
[0036] The MEMS sensors suitable for use in conjunction with
MEMS-LCMS that include passive RFIDs may be active RFID readers,
which are well-known in the RFID art.
[0037] Additional examples of the MEMS portion of the MEMS-LCMs
described herein and MEMS sensors may include, but are not limited
to, active RFIDs with RFID readers (e.g., RFIDs having a battery
and periodically transmitting an identifying signal) and
battery-assisted passive RFID with RFID readers (e.g., RFIDs having
a battery and activated to transmit an identifying signal in the
presence of the RFID reader).
[0038] The MEMS-LCMs may be included in a drilling fluid 122
described herein at about 0.001 PPB to about 150 PPB in the
drilling fluid, including any subset therebetween.
[0039] The MEMS-LCMs described herein may be formed of a MEMS
coupled to or incorporated into polymers (e.g.,
polytetrafluoroethylene, fluoropolyesters, polypropylene,
polyethylene, polydimethylsilane, polylactic acid,
poly(lactic-co-glycolic acid), cellulosics, metals (e.g., stainless
steel and tin), ceramics (e.g., oxides like alumina, carbides,
borides, nitrides, and silicides), minerals (e.g., kaolin and
feldspar), glasses, borosilicate glass, or the like, including any
material described herein relative to the LCMs, to form the
MEMS-LCMs described herein.
[0040] The MEMS-LCMs described herein may, in some instances, have
a specific gravity of about 0.5 to about 7, including any subset
therebetween.
[0041] The MEMS-LCMs described herein may be any known shapes of
materials, including substantially spherical materials, fibrous
materials, polygonal materials (such as cubic materials), and
combinations thereof.
[0042] The MEMS-LCMs described herein may, in some instances, have
a diameter of about 1 micron or greater (e.g., about 1 micron to
about 25 mm, including any subset therebetween). Generally, the
upper size limit for the MEMS-LCMs is dictated by the nozzles of
the drill bit, which may, in some instances, be up to about 30 mm.
As used herein, the term "diameter" refers to the smallest
cross-sectional diameter of the MEMS-LCM.
[0043] The drilling fluids 122 described herein may optionally
further include an additive. The additives may be included may be
included at about 0.001 PPB to about 150 PPB in the treatment
fluid, including any subset therebetween.
[0044] Examples of additives may include, but are not limited to,
salts, weighting agents, inert solids, emulsifiers, dispersion
aids, corrosion inhibitors, emulsion thinners, emulsion thickeners,
viscosifying agents, surfactants, pH control additives, foaming
agents, breakers, biocides, crosslinkers, stabilizers, chelating
agents, scale inhibitors, gas, oxidizers, reducers, and any
combination thereof. A person of ordinary skill in the art, with
the benefit of this disclosure, will recognize when an additive
should be included in a wellbore strengthening fluid and/or
drilling fluid, as well as an appropriate amount of said additive
to include.
[0045] In some instances, the disclosed MEMS-LCMs may directly or
indirectly affect the components and equipment of the disclosed
drilling assemblies 100,200,300,400. For example, the MEMS-LCMs may
directly or indirectly affect the fluid processing unit(s) 128
which may include, but is not limited to, one or more of a shaker
(e.g., shale shaker), a centrifuge, a hydrocyclone, a separator
(including magnetic and electrical separators), a desilter, a
desander, a filter (e.g., diatomaceous earth filters), a heat
exchanger, or any fluid reclamation equipment. The fluid processing
unit(s) 128 may further include one or more sensors, gauges, pumps,
compressors, and the like used to store, monitor, regulate, and/or
recondition the exemplary MEMS-LCMs.
[0046] The disclosed MEMS-LCMs may directly or indirectly affect
the pump 120, which representatively includes any conduits,
pipelines, trucks, tubulars, and/or pipes used to fluidically
convey the MEMS-LCMs downhole, any pumps, compressors, or motors
(e.g., topside or downhole) used to drive the MEMS-LCMs into
motion, any valves or related joints used to regulate the pressure
or flow rate of the MEMS-LCMs, and any sensors (i.e., pressure,
temperature, flow rate, etc.), gauges, and/or combinations thereof,
and the like. The disclosed MEMS-LCMs may also directly or
indirectly affect the mixing hopper 134 and the retention pit 132
and their assorted variations.
[0047] The disclosed MEMS-LCMs may also directly or indirectly
affect the various downhole equipment and tools that may come into
contact with the MEMS-LCMs such as, but not limited to, the drill
string 108, any floats, drill collars, mud motors, downhole motors
and/or pumps associated with the drill string 108, and any MWD/LWD
tools and related telemetry equipment, sensors or distributed
sensors associated with the drill string 108. The disclosed
MEMS-LCMs may also directly or indirectly affect any downhole heat
exchangers, valves and corresponding actuation devices, tool seals,
packers and other wellbore isolation devices or components, and the
like associated with the wellbore 116. The disclosed MEMS-LCMs may
also directly or indirectly affect the drill bit 114, which may
include, but is not limited to, roller cone bits, PDC bits, natural
diamond bits, any hole openers, reamers, coring bits, etc.
[0048] While not specifically illustrated herein, the disclosed
MEMS-LCMs may also directly or indirectly affect any transport or
delivery equipment used to convey the MEMS-LCMs to the drilling
assembly 100,200,300,400 such as, for example, any transport
vessels, conduits, pipelines, trucks, tubulars, and/or pipes used
to fluidically move the MEMS-LCMs from one location to another, any
pumps, compressors, or motors used to drive the MEMS-LCMs into
motion, any valves or related joints used to regulate the pressure
or flow rate of the MEMS-LCMs, and any sensors (i.e., pressure and
temperature), gauges, and/or combinations thereof, and the
like.
[0049] In some embodiments, a wellbore may be drilled penetrating a
subterranean formation with a drilling fluid that includes a base
fluid, at least one type of MEMS-LCMs, and at least one LCM that is
substantially similar to at least one of the types of MEMS-LCMs.
The absence, presence, or concentration of the various types of
MEMS-LCMs may be measured with MEMS sensors disposed in a drilling
assembly in at least one location selected from the group
consisting of (1) along the drill string; (2) along a feed pipe
fluidly coupled to the drill string upstream of the wellbore; (3)
along a flow line fluidly coupled to the drill string downstream of
the wellbore; (4) at the wellhead, (5) at the pump, (6) at a slip
joint in a subsea drilling assembly, (7) at a riser of a subsea
drilling assembly, (8) at a BOP, (9) along a casing, and (10) along
a wireline extending into a portion of the wellbore. The absence,
presence, or concentration of the various types of MEMS-LCMs at
each location may be compared, and the comparison may be used in
changing the composition of the drilling fluid.
[0050] In some instances, the composition of the drilling fluid may
be changed by adding LCMs with greater diameter or density than the
MEMS-LCMs that experience lost circulation. Further, the
concentration of LCMs substantially similar to the MEMS-LCMs that
experience lost circulation may be decreased.
[0051] In some instances, the composition of the drilling fluid may
be changed by adding LCMs that are substantially similar to the
MEMS-LCMs that provide wellbore strengthening. In some instances,
the properties of the drilling fluid may be changed. For example,
the rheology may be changed by adding a viscosifier or adding a
breaker. In another example, the water:oil ratio may be changed. In
yet another example, the density or weight of the drilling fluid
may be changed by increasing the concentration of weighting agents
or light-weight additives in the drilling fluid. In another
example, the gel strength of the drilling fluid may be changed by
adding a crosslinker or breaker to the drilling fluid.
[0052] Alternatively or in combination with changes to the drilling
fluid composition, the drilling parameters may be changed in
response to the evaluation of wellbore strengthening and lost
circulation. Exemplary parameters may include, but are not limited
to, rate of penetration of the drill bit into the formation,
circulation rate or flow rate of the drilling fluid, reaming,
weight on bit, rpm of the drill bit, choke pressure (e.g., in
managed pressure drilling operations), and the like.
[0053] The information garnered from the methods described herein
may be applied to simulating further drilling operations. For
example, in some instances, the data collected from a drilling
operation using the MEMS-LCMs may be stored and used in a program
that uses geo-mechanical models to build drilling programs for
other wells. The collected data may include the characteristics of
the MEMS-LCMs (e.g., size, specific gravity, and shape) that
provide for wellbore strengthening, experience fluid loss into the
formation, or neither (i.e., pass through the system substantially
unchanged in concentration). The collected data may also include
such characteristics and performance downhole correlated to the
lithology (i.e., rock characteristics) of the formation.
[0054] Embodiments disclosed herein include Embodiment A,
Embodiment B, and Embodiment C.
[0055] Embodiment A is a method that includes drilling at least a
portion of a wellbore penetrating a subterranean formation with a
drilling fluid that comprises a base fluid, a plurality of
MEMS-LCMs, and a plurality of LCMs, wherein the MEMS-LCMs and the
LCMs are substantially similar in size, shape, and specific
gravity; measuring a first concentration of the MEMS-LCMs in the
drilling fluid before circulating the drilling fluid through the
wellbore; measuring a second concentration of the MEMS-LCMs in the
drilling fluid after circulating the drilling fluid through the
wellbore; performing a comparison of the first and second
concentrations of the MEMS-LCMs; and changing a composition of the
drilling fluid based on the comparison.
[0056] Embodiment A may have one or more of the following
additional elements in any combination: Element A1: the method
further including measuring a third concentration of the MEMS-LCMs
in the drilling fluid while the drilling fluid is circulating
through the wellbore; and wherein performing the comparison of the
first and second concentrations of the MEMS-LCMs further involves
comparing the first, second, and third concentrations of MEMS-LCMs;
Element A2: wherein changing the composition of the drilling fluid
involves increasing the concentration of the LCMs; Element A3:
wherein the LCMs are first LCMs, and wherein changing the
composition of the drilling fluid involves adding a plurality of
second LCMs to the drilling fluid; Element A4: Element A3 and
wherein the second LCMs have a larger diameter than the first LCMs;
Element A5: Element A3 and wherein the second LCMs have a greater
specific gravity than the first LCMs; Element A6: wherein the LCMs
are first LCMs and the MEMS-LCMs are first MEMS-LCMs, the drilling
fluid further comprising a plurality of second LCMs and a plurality
of second MEMS-LCMs, wherein the second MEMS-LCMs and the second
LCMs are substantially similar in size, shape, and specific
gravity, and wherein the first MEMS-LCMs and the second MEMS-LCMs
exhibit different signatures readable by a MEMS sensor, the method
further comprising: measuring a first concentration of the second
MEMS-LCMs in the drilling fluid before circulating the drilling
fluid through the wellbore; measuring a second concentration of the
second MEMS-LCMs in the drilling fluid after circulating the
drilling fluid through the wellbore; performing a second comparison
of the first and second concentrations of the second MEMS-LCMs; and
changing the composition of the drilling fluid based on the
comparison and the second comparison; and Element A7: wherein the
plurality of the MEMS-LCMs comprise a passive RFID.
[0057] By way of non-limiting example, exemplary combinations
applicable to Embodiment A include: Element A1 in combination with
Element A2; Element A3 in combination with at least one of Elements
A1 and A2 and optionally in further combination with at least one
of Elements A4 and A5; Element A6 in combination with any of the
foregoing; Element A6 in combination with at least one of Elements
A1-A5; Element A7 in combination with any of the foregoing; and
Element A7 in combination with at least one of Elements A1-A6.
[0058] Embodiment B is a method that includes drilling at least a
portion of a wellbore penetrating a subterranean formation with a
drilling fluid that comprises a base fluid, a plurality of
MEMS-LCMs, and a plurality of LCMs, wherein the MEMS-LCMs and the
LCMs are substantially similar in size, shape, and specific
gravity; measuring a first concentration and a second concentration
of the MEMS-LCMs in the drilling fluid at a first location and a
second location in the wellbore; performing a comparison of the
first and second concentrations of the MEMS-LCMs; and changing a
composition of the drilling fluid based on the comparison.
[0059] Embodiment B may have one or more of the following
additional elements in any combination: Element B1: measuring a
third concentration of the MEMS-LCMs in the drilling fluid before
circulating the drilling fluid through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, and
third concentrations of MEMS-LCMs; Element B2: measuring a third
concentration of the MEMS-LCMs in the drilling fluid after
circulating the drilling fluid through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, and
third concentrations of MEMS-LCMs; Element B3: measuring a third
concentration of the MEMS-LCMs in the drilling fluid before
circulating the drilling fluid through the wellbore; measuring a
fourth concentration of the MEMS-LCMs in the drilling fluid after
circulating the drilling fluid through the wellbore; and wherein
performing the comparison of the first and second concentrations of
the MEMS-LCMs further involves comparing the first, second, third,
and fourth concentrations of MEMS-LCMs; Element B4: wherein
changing the composition of the drilling fluid involves increasing
the concentration of the LCMs; Element B5: wherein the LCMs are
first LCMs, and wherein changing the composition of the drilling
fluid involves adding a plurality of second LCMs to the drilling
fluid; Element B6: wherein the LCMs are first LCMs and the
MEMS-LCMs are first MEMS-LCMs, the drilling fluid further
comprising a plurality of second LCMs and a plurality of second
MEMS-LCMs, wherein the second MEMS-LCMs and the second LCMs are
substantially similar in size, shape, and specific gravity, and
wherein the first MEMS-LCMs and the second MEMS-LCMs exhibit
different signatures readable by a micro-electro-mechanical systems
(MEMS) sensor, the method further comprising: measuring a first
concentration and a second concentration of the second MEMS-LCMs in
the drilling fluid at the first location and the second location in
the wellbore; performing a second comparison of the first and
second concentrations of the second MEMS-LCMs; and changing the
composition of the drilling fluid based on the comparison and the
second comparison; and Element B7: wherein the plurality of the
MEMS-LCMs comprise a passive RFID.
[0060] By way of non-limiting example, exemplary combinations
applicable to Embodiment B include: one of Elements B1-B3 in
combination with Element B4; one of Elements B1-B3 in combination
with Element B5 and optionally in further combination with Element
B4; Element B6 in combination with one of Elements B1-B3; Element
B6 in combination with at least one of Elements B4-B5 and
optionally in further combination with one of Elements B1-B3;
Element B7 in combination with any of the foregoing; Element B7 in
combination with one of Elements B1-B3; and Element B7 in
combination with at least one of Elements B4-B6.
[0061] Embodiment C is a system that includes a drilling assembly
with a drill string extending therefrom, through a blowout
preventer (BOP) and a wellhead and into a wellbore penetrating a
subterranean formation; a wireline extending from the drilling
assembly and into the wellbore; a pump fluidly coupled to the drill
string, the drill string containing a drilling fluid that comprises
a base fluid, a plurality of MEMS-LCMs, and a plurality of LCMs,
wherein the MEMS-LCMs and the LCMs are substantially similar in
size, shape, and specific gravity; and at least one MEMS sensor in
at least one location selected from the group consisting of (1)
along the drill string; (2) along a feed pipe fluidly coupled to
the drill string upstream of the wellbore; (3) along a flow line
fluidly coupled to the drill string downstream of the wellbore; (4)
at the wellhead, (5) at the pump, (6) at the BOP, (7) along the
casing, and (8) along the wireline. Embodiment C may further
include wherein the at least one MEMS sensor is an active RFID
reader and the plurality of the MEMS-LCMs comprise a passive
RFID.
[0062] Unless otherwise indicated, all numbers expressing
quantities of ingredients, properties such as molecular weight,
reaction conditions, and so forth used in the present specification
and associated claims are to be understood as being modified in all
instances by the term "about." Accordingly, unless indicated to the
contrary, the numerical parameters set forth in the following
specification and attached claims are approximations that may vary
depending upon the desired properties sought to be obtained by the
embodiments of the present invention. At the very least, and not as
an attempt to limit the application of the doctrine of equivalents
to the scope of the claim, each numerical parameter should at least
be construed in light of the number of reported significant digits
and by applying ordinary rounding techniques.
[0063] One or more illustrative embodiments incorporating the
invention embodiments disclosed herein are presented herein. Not
all features of a physical implementation are described or shown in
this application for the sake of clarity. It is understood that in
the development of a physical embodiment incorporating the
embodiments of the present invention, numerous
implementation-specific decisions must be made to achieve the
developer's goals, such as compliance with system-related,
business-related, government-related and other constraints, which
vary by implementation and from time to time. While a developer's
efforts might be time-consuming, such efforts would be,
nevertheless, a routine undertaking for those of ordinary skill in
the art and having benefit of this disclosure.
[0064] While compositions and methods are described herein in terms
of "comprising" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps.
[0065] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. While compositions and methods
are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. All numbers and ranges disclosed
above may vary by some amount. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range is specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. Moreover, the indefinite articles
"a" or "an," as used in the claims, are defined herein to mean one
or more than one of the element that it introduces.
* * * * *