U.S. patent application number 14/272141 was filed with the patent office on 2015-11-12 for drill cuttings re-injection.
The applicant listed for this patent is Ramesh Varadaraj. Invention is credited to Ramesh Varadaraj.
Application Number | 20150322762 14/272141 |
Document ID | / |
Family ID | 54367381 |
Filed Date | 2015-11-12 |
United States Patent
Application |
20150322762 |
Kind Code |
A1 |
Varadaraj; Ramesh |
November 12, 2015 |
Drill Cuttings Re-Injection
Abstract
Methods and compositions for re-injecting formation solids such
as drillbit cuttings into a subsurface formation including:
obtaining a volume of solid particles comprising a non-aqueous
fluid; obtaining a slurry-forming fluid, the slurry-forming fluid
comprising water, salt, a viscosifying water soluble polymer, and
an oily solids aggregator; mixing the obtained solid particles and
the slurry-forming fluid to create an injectable slurry; and
introducing the injectable slurry into a wellbore for injection
into a subsurface formation.
Inventors: |
Varadaraj; Ramesh;
(Bartlesville, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Varadaraj; Ramesh |
Bartlesville |
OK |
US |
|
|
Family ID: |
54367381 |
Appl. No.: |
14/272141 |
Filed: |
May 7, 2014 |
Current U.S.
Class: |
166/265 |
Current CPC
Class: |
C09K 8/80 20130101; C09K
8/90 20130101; E21B 43/267 20130101; C09K 8/92 20130101; E21B
21/066 20130101; E21B 41/0057 20130101; C09K 8/88 20130101 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A method for injecting solid particles recovered from a NAF
drilling cuttings returns fluid stream into a subsurface formation,
comprising: obtaining solid particles from a drilling returns
stream comprising a NAF, the obtained solid particles comprising
NAF; obtaining a slurry-forming fluid, the slurry-forming fluid
comprising water, a viscosifying water soluble polymer, and an oily
solids aggregator; mixing the obtained solid particles and the
slurry-forming fluid to create an injectable slurry; and
introducing the injectable slurry into a wellbore for injection
into a subsurface formation.
2. The method of claim 1, further comprising pumping the injectable
slurry into the wellbore and into one or more fractures formed in
the subsurface formation.
3. The method of claim 1, wherein the oily solids aggregator
comprises an ionic water soluble polymer.
4. The method of claim 1, wherein the oily solids aggregator
comprises at least one of hydrolyzed polyacrylamide (HPAM) and
sulfonated polystyrene.
5. The method of claim 1, wherein the viscosifying water soluble
polymer comprises at least one of a polysaccharide, guar gum,
xanthan, alginate, pectin, cellulosic polymer, and a viscosifying
hydrocolloid.
6. The method of claim 1, wherein the viscosifying water soluble
polymer comprises at least one of carboxyl-methylcellulose (CMC)
and xanthan gum.
7. The method of claim 1, wherein the water comprises at least 0.5
wt % (5 ppt) salt based upon the total weight of the water, wherein
the salt comprises at least one of a dissolved chloride and bromide
salt.
8. The method of claim 1, wherein the slurry-forming fluid
aggregates solids within a size range of 0.2 to 50 micron size
solid particles.
9. The method of claim 1, further comprising separating the
obtained solid particles from at least a portion of the non-aqueous
drilling fluid, wherein the separated obtained solid particles
comprise a coating of non-aqueous drilling fluid.
10. The method of claim 1, further comprising combining salt water,
the water soluble polymer, the oily solids aggregator, and
NAF-coated solid particles to form the injectable slurry.
11. The method of claim 1, wherein the water comprises a chloride
or bromide salt of at least one of sodium, calcium, and
magnesium.
12. The method of claim 1, wherein the injectable slurry comprises
from 50 to 80 wt % of water, based upon the total weight of the
injectable slurry.
13. The method of claim 1, wherein the injectable slurry comprises
from 60 to 70 wt % of water, based upon the total weight of the
injectable slurry.
14. The method of claim 1, wherein the injectable slurry comprises
from 15 to 50 wt % of solid particles, based upon the total weight
of the injectable slurry.
15. The method of claim 1, wherein the injectable slurry comprises
from 20 to 30 wt % of solid particles, based upon the total weight
of the injectable slurry.
16. The method of claim 1, wherein the injectable slurry comprises
from 5 to 25 wt % of NAF, based upon the total weight of the
injectable slurry.
17. The method of claim 1, wherein the injectable slurry comprises
from 5 to 20 wt % of NAF, based upon the total weight of the
injectable slurry.
18. The method of claim 1, wherein the injectable slurry comprises
NAF at a concentration of from 1 wt % to 25 wt %, based upon the
total weight of the injectable slurry.
19. The method of claim 2, further comprising pumping a volume of a
NAF filter cake remediation fluid into the disposal well prior to
pumping the injectable slurry.
20. The method of claim 2, further comprising pumping a volume of
the NAF into the disposal well prior to pumping the injectable
slurry into the disposal well.
21. The method of claim 1, wherein the injectable slurry comprises
the oily solids aggregator in the range of 0.01 to 5 wt % based on
the total weight of the slurry composition.
22. The method of claim 1, wherein the injectable slurry comprises
the oily solids aggregator in the range of 0.01 to 1.0 wt % based
on the total weight of the slurry composition.
23. The method of claim 1, wherein the injectable slurry comprises
the oily solids aggregator in the range of 0.05 to 0.5 wt % based
on the total weight of the slurry composition.
24. An injectable fluid for use in re-injecting solid particles
recovered from a NAF drilling fluid into a subsurface formation,
comprising: a slurry-forming fluid, the slurry-forming fluid
comprising water, salt, a viscosifying water soluble polymer, an
oily solids aggregator polymer, and a NAF.
25. The fluid of claim 24, further comprising solid particles
comprising drill cuttings and the NAF.
26. The fluid of claim 24, wherein the oily solids aggregator
comprises an ionically responsive water soluble polymer.
27. The fluid of claim 24, wherein the oily solids aggregator
comprises at least one of hydrolyzed polyacrylamide (HPAM) and
sulfonated polystyrene.
28. The fluid of claim 24, wherein the water soluble polymer
comprises at least one of a polysaccharide, guar gum, alginate,
pectin, cellulosic polymer, and another hydro-colloid.
29. The fluid of claim 24, wherein the water soluble polymer
comprises at least one of carboxyl-methylcellulose (CMC) and
Xanthan gum.
30. The fluid of claim 24, wherein the water comprises at least 0.5
wt % (5 ppt) salt, based upon the total weight of the water in the
injectable slurry, wherein the salt comprises at least one of a
dissolved chloride and bromide salt of at least one of sodium,
potassium, calcium, and magnesium.
31. The fluid of claim 25, further comprising NAF in addition to
the NAF that is associated with the drill cuttings.
32. The fluid of claim 24, wherein the slurry-forming fluid further
comprises a chloride or bromide salt of at least one of sodium,
calcium, and magnesium.
33. The fluid of claim 24, wherein the injectable slurry comprises
from 50 to 80 wt % of water, based upon the total weight of the
injectable slurry.
34. The fluid of claim 24, wherein the injectable slurry comprises
from 60 to 70 wt % of water, based upon the total weight of the
injectable slurry
35. The fluid of claim 24, wherein the injectable slurry comprises
from 15 to 40 wt % of solid particles, based upon the total weight
of the injectable slurry.
36. The fluid of claim 24, wherein the injectable slurry comprises
from 20 to 30 wt % of solid particles, based upon the total weight
of the injectable slurry.
37. The fluid of claim 24, wherein the injectable slurry comprises
from 5 to 30 wt % of NAF, based upon the total weight of the
injectable slurry.
38. The fluid of claim 24, wherein the injectable slurry comprises
NAF at a concentration of from 1 wt % to 25 wt %, based upon the
total weight of the injectable slurry.
39. The fluid of claim 28, wherein the solid particles comprise at
least 10 wt % of the solid particles having a mean diameter of from
0.2 to 50 microns, based upon the total weight of the solid
particles.
40. The fluid of claim 24 wherein the injectable slurry comprises
the oily solids aggregator in the range of 0.01 to 5 wt % based on
the total weight of the slurry composition.
41. The fluid of claim 24, wherein the injectable slurry comprises
the oily solids aggregator in the range of 0.01 to 1.0 wt % based
on the total weight of the slurry composition.
42. The fluid of claim 24, wherein the injectable slurry comprises
the oily solids aggregator in the range of 0.05 to 0.5 wt % based
on the total weight of the slurry composition.
Description
BACKGROUND OF THE INVENTION
[0001] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
FIELD OF THE INVENTION
[0002] This invention relates generally to the field of wellbore
operations. More specifically, in some applications the invention
relates to the re-injection of drill cuttings and solids generated
during the formation of a wellbore.
GENERAL DISCUSSION OF TECHNOLOGY
[0003] During drilling of a wellbore such as for use in hydrocarbon
production operations, a wellbore is formed using a drill string
and drill bit while a drilling fluid (generally referred to as
drilling "mud") is circulated through the drill string and bit and
then up the backside annulus out of the wellbore, to remove the
cuttings. These cuttings typically represent bits of formation rock
being drilled, such as clay, shale, quartz, carbonate, etc.
Typically, the mud and cuttings are circulated back to the surface
where the cuttings are separated from the mud using solids control
equipment. The solids control equipment typically includes screens,
so-called "shakers," and gravity separation that filters out the
majority of solids while recovering a substantial portion of the
drilling mud for reuse. The majority of the recovered cuttings are
stored and/or readied for disposal, such as by removal to a remote
surface location or injection down a disposal well.
[0004] Cuttings re-injection operations ("CRI") generally started
in the late 1980's. CRI may offer an environmentally friendly and
economically attractive solution for disposal of cuttings from a
drilling operation, particularly cuttings where the base fluid is
or comprises an a non-aqueous fluid (NAF) such as an oil or
hydrocarbon component. CRI may eliminate surface discharge and
provide for the efficient recovery of a portion of the disposal
fluid for reuse in other CRI disposal operations. When operations
are complete, the disposal well is securely plugged and
abandoned.
[0005] Environmental regulations in some areas may prevent the
immediate surface (or near-surface) disposal or injection of drill
cuttings when such cuttings contain residual non-aqueous fluids or
NAF's, such as hydrocarbon-based or synthetic-based drilling mud.
Disposal procedures may require "cleaning" and otherwise preparing
NAF cuttings prior to disposal. A typical drill-cuttings CRI
operation may involve processing the solids in a slurrification
unit, where the cuttings may be ground into smaller particles in
the presence of water to form an aqueous-based slurry. A residual
portion of the drilling mud (aqueous or NAF) may also still remain
in the aqueous slurry. The slurry may be subjected to still further
rheological conditioning. The suitably conditioned drill cuttings
slurry may then be injected into a subsurface formation using a
wellbore for accessing the formation. The injected slurry is
introduced into the formation and into subsurface fractures created
by injecting the slurry under relatively high pressure in a
disposal formation.
[0006] Various technical challenges exist with respect to CRI, such
as fluid rheology, avoiding formation plugging and fracture growth.
Slurry rheology design includes properties, such as slurry
viscosity, suspension capacity, get strength, and particle size
limitations. The slurry must have adequate viscosity and
solids-carrying capacity to transport the particles into the
formation. The particles must be able to enter and move within the
fractures to avoid plugging. The oily solids of the NAF can not
only adversely change the designed slurry rheology but also
directly contribute to plugging of formation pores and result in
slowing the desired leak-off of the slurry water. Lack of fluid
leak-off may produce excessive fracture growth and/or plugging,
leading to increased injection pressures.
[0007] When injecting disposal slurries, the created fracture
volume must be sufficient to accommodate the injected material.
Ideally, the fluid portion of the injected material is permitted to
leak off into the formation pores as the slurry is injected such
that the created fracture need primarily accommodate the solids
portion of the injected material. However, formation and fracture
face plugging may prevent fluid leak-off into the formation,
thereby requiring the fracture volume to accommodate both the
injected solids and a substantial portion of the fluid phase. Such
fracture face and formation pore plugging can lead to increased
injection pressures, premature fracture filling, and/or potential
loss of injection conformance. Need exists for an improved slurry
performance for re-injection of drill cuttings, especially
regarding NAF drill cuttings, into a disposal formation.
SUMMARY OF THE INVENTION
[0008] Methods, compositions, and systems for re-injecting drill
cuttings into a subsurface formation are provided. The methods
described herein have various benefits related to the conducting of
oil and gas exploration and production activities, especially
regarding wellbore drilling, and more particularly with regard to
disposal of NAF cuttings produced during. The present disclosure
includes methods, systems, and apparatus that overcome many of the
formation plugging problems related to reinjection of NAF
cuttings.
[0009] A method is disclosed that includes obtaining a volume of
solid particles from NAF drilling returns and introducing the same
into a slurry-forming fluid to create injectable slurry. The solid
particles primarily represent formation cuttings recovered from a
drilling operation, but may also represent various other recovered
solids that had been previously added to the NAF drilling fluid,
such as lost circulation materials, weighting agents, and formation
debris. The solid particles are typically coated with and/or
dispersed within some NAF drilling fluid.
[0010] A method is disclosed for injecting the solid particles
recovered from a NAF drilling cuttings returns fluid stream into a
subsurface formation. The method may include obtaining and
associated NAF; obtaining a slurry-forming fluid, the
slurry-forming fluid including water, a viscosifying water soluble
polymer, and an oily solids aggregator; mixing the obtained solid
particles and the slurry-forming fluid to create an injectable
slurry; and introducing the injectable slurry into a wellbore for
injection into a subsurface formation.
[0011] An injectable fluid is provided that may be suitable for use
in re-injecting solid particles recovered from a NAF drilling fluid
into a subsurface formation, the fluid comprising a slurry-forming
fluid, the slurry-forming fluid comprising water, a viscosifying
water soluble polymer, and an oily solids aggregator and NAF. The
injectable fluid may also include drill cuttings, particularly
NAF-containing cuttings, or other solid particulates that may be
mixes with the slurry-forming fluid.
[0012] In the present methods, and compositions, the oily solids
aggregator may include at least one ionic water soluble polymer and
at least one viscosifying water soluble polymer. Exemplary ionic
water soluble polymers may include hydrolyzed polyacrylamide (HPAM)
and sulfonated polystyrene. Exemplary viscosifying water soluble
polymers may include a polysaccharide, guar gum, xanthan gum,
alginate, pectin, cellulosic polymer, carboxyl-methylcellulose
(CMC) and xanthan gum, and another hydrocolloid.
[0013] The methods and compositions may include a surfactant that
comprises a weak acid, a weak base, or both. In one aspect, the
surfactant is an alkyl acid surfactant, an organo-anionic
surfactant, or mixtures thereof. Where the surfactant is or
includes an organo-anionic surfactant, the organo-ionic surfactant
is preferably selected from the group comprising monoethanol
ammonium alkyl aromatic sulfonic acid, monoethanol ammonium alkyl
carboxylic acid, and mixtures thereof.
[0014] The operations fluid may be injected into the borehole of a
disposal well in order to remediate a NAF filter cake along the
borehole. Preferably, the method also includes mixing a volume of
the operations fluid with the volume of solid particles to form an
operations fluid slurry. The method then includes pumping the
slurry into the disposal well.
[0015] The method further includes injecting the slurry into one or
more fractures formed in the subsurface formation. Injection is
conducted in such a manner that the slurry contacts the NAF filter
cake en route to the one or more fractures. Because of the weak
base--weak acid formulation of the slurry, the NAF filter cake is
degraded, thereby facilitating the injection of the slurry into
fractures along the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] So that the present inventions can be better understood,
certain drawings, charts, graphs and/or flow charts are appended
hereto. It is to be noted, however, that the drawings illustrate
only selected embodiments of the inventions and are therefore not
to be considered limiting of scope, for the inventions may admit to
other equally effective embodiments and applications.
[0017] FIG. 1 illustrates a well site and bore of an exemplary
facility for re-injection of cuttings for disposal.
[0018] FIG. 2 is a. comparative plot of filtration resistance for
an aqueous based fluid slurry containing solids as an injectable
slurry.
[0019] FIG. 3 adds a comparative plot of filtration resistance for
a non-aqueous based fluid slurry containing solids as an injectable
slurry.
[0020] FIG. 4 is a comparative graph of viscosity of the
comparative fluids of FIG. 2 and FIG. 3.
[0021] FIG. 5 is an exemplary graph of viscosity of the disclosed
fluid composition versus the comparative fluids of FIG. 2 and FIG.
3.
[0022] FIG. 6 is an exemplary plot of filtration resistance for the
disclosed fluid composition versus the comparative fluids of FIG. 2
and FIG. 3.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0023] For purposes of the present application, it will be
understood that the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Hydrocarbons may also include other elements,
such as, but not limited to, halogens, metallic elements, nitrogen,
oxygen, and/or sulfur. Hydrocarbons generally fall into two
classes: aliphatic, or straight chain hydrocarbons, and cyclic, or
closed ring hydrocarbons, including cyclic terpenes. Examples of
hydrocarbon-containing materials include any form of natural gas,
natural or synthetic oil, coal, and bitumen that can be used as a
fuel or upgraded into a fuel.
[0024] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions or at ambient conditions
(15.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and
other hydrocarbons that are in a gaseous or liquid state.
[0025] As used herein, the terms "produced fluids" and "production
fluids" refer to liquids and/or gases removed from a subsurface
formation, including, for example, an organic-rich rock formation.
Produced fluids may include both hydrocarbon fluids and
non-hydrocarbon fluids. Production fluids may include, but are not
limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a
pyrolysis product of coal, carbon dioxide, hydrogen sulfide and
water (including steam).
[0026] As used herein, the term "fluid" refers to gases, liquids,
and combinations of gases and liquids, as well as to combinations
of gases and solids, combinations of liquids and solids, and
combinations of gases, liquids, and solids.
[0027] As used herein, the term "gas" refers to a fluid that is in
its vapor phase at 1 atm and 15.degree. C.
[0028] As used herein, the term "oil" refers to a hydrocarbon fluid
containing primarily a mixture of condensable hydrocarbons.
[0029] As used herein, the term "subsurface" refers to geologic
strata occurring below the earth's surface.
[0030] As used herein, the term "formation" refers to any definable
subsurface region regardless of size. The formation may contain one
or more hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation. A formation can refer to a single set of
related geologic strata of a specific rock type, or to a set of
geologic strata of different rock types that contribute to or are
encountered in, for example, without limitation, (i) the creation,
generation and/or entrapment of hydrocarbons or minerals, and (ii)
the execution of processes used to extract hydrocarbons or minerals
from the subsurface.
[0031] The terms "zone" or "zone of interest" refers to a portion
of a formation containing hydrocarbons. Alternatively, the
formation may be a water-bearing interval.
[0032] For purposes of the present patent, the term "production
casing" includes a liner string or any other tubular body fixed in
a wellbore along a zone of interest.
[0033] As used herein, the term "drilling returns" means a slurry
containing a liquid and a solid, wherein the slurry includes drill
cuttings from a subsurface formation.
[0034] As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shapes. As used herein, the term
"well," when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS
[0035] The inventions are described herein in connection with
certain specific embodiments. However, to the extent that the
following detailed description is specific to a particular
embodiment or a particular use, such is intended to be illustrative
only and is not to be construed as limiting the scope of the
inventions or other embodiments.
[0036] FIG. 1 presents a side view of a well site 100 wherein a
well is being completed. The well is a disposal well for the
injection of drill cuttings.
[0037] The well site 100 generally includes a wellbore 150 and a
wellhead 170. The wellbore 150 includes a bore 115 for receiving
drilling equipment and fluids. The bore 115 extends from the
surface 105 of the earth, and into the earth's subsurface 110. The
wellbore 150 is being completed in a subsurface formation,
indicated by bracket 160.
[0038] The wellbore 150 is first formed with a string of surface
casing 120. The surface casing 120 has an upper end 122 in sealed
connection with a lower master fracture valve 125. The surface
casing 120 also has a lower end 124. The surface casing 120 is
secured in the wellbore 150 with a surrounding cement sheath
112.
[0039] The wellbore 150 also includes a lower string of casing 130.
The lower string of casing 130 is also secured in the wellbore 150
with a surrounding cement sheath 114. The lower string of casing
130 has an upper end 132 in sealed connection with an upper master
fracture valve 135. The lower string of casing 130 also has a lower
end 134.
[0040] In the well site 100 of FIG. 1, the lower string of casing
130 does not extend to a bottom 136 of the wellbore 150. Instead, a
lower portion of the wellbore 150 is left uncased. In this way, the
wellbore 150 is completed as an open-hole, particularly along the
subsurface formation 160. However, it is understood that the
wellbore 150 could be completed as a cased hole. In this instance,
the lower string of casing 130 would be a string of "production
casing" that extends to the bottom 136 of the wellbore 150. In that
instance, the casing would be perforated to allow for fluid
communication between the bore 115 of the wellbore 150 and the
subsurface formation 160.
[0041] It is understood that the depth of the wellbore 150 may
extend many thousands of feet below the earth surface 105. In this
way, the subsurface formation 160 may be fractured without concern
over creating fluid communication with any near-surface
aquifers.
[0042] As noted, the well site 100 also includes a wellhead 170.
The wellhead 170 is used during the completion phase of the
wellbore 150. The wellhead 170 includes one or more blow-out
preventers. The blow-out preventers are typically remotely actuated
in the event of operational upsets. In more shallow wells, or in
wells having lower formation pressures, the master fracture valves
125, 135 may be the blow-out preventers. In either event, the
master fracture valves 125, 135 are used to selectively seal the
bore 115.
[0043] The wellhead 170 and its components are used for flow
control and hydraulic isolation during rig-up operations, during
fracturing and fluid injecting operations, and during rig-down
operations. The wellhead 170 may include a crown valve 172. The
crown valve 172 is used to isolate the wellbore 150 in the event a
lubricator (not shown) or other components are placed above the
wellhead 170. The wellhead 170 further includes side outlet
injection valves 174. The side outlet injection valves 174 are
located within fluid injection lines 171. The fluid injection lines
171 provide a means for the injection of fracturing fluids,
weighting fluids, and/or drill cuttings slurry into the bore 115,
with the injection of the fluids being controlled by the valves
174.
[0044] The piping from surface pumps (not shown) and tanks (not
shown) used for injection of fluids or cuttings-slurries are in
fluid communication with the valves 174. Appropriate hoses,
fittings and/or couplings (not shown) are employed. The fluids are
then pumped into the lower string of casing 130 and the open-hole
portion of the wellbore 150, adjacent subsurface formation 160.
[0045] It is understood that the various wellhead components shown
in FIG. 1 are merely illustrative. A typical completion operation
will include numerous valves, pipes, tanks, fittings, couplings,
gauges, and other fluid control devices. These may include a
pressure-equalization line and a pressure-equalization valve (not
shown) for positioning a tool string above the lower valve 125
before a tool string is dropped into the bore 115. Downhole
equipment may be run into and out of the wellbore 150 using an
electric line, slick line or coiled tubing. Further, a drilling rig
or other platform may be employed, with jointed working tubes or
coiled tubing being used as needed.
[0046] The wellbore 150 has been formed through the use of a drill
string and connected drill bit (not shown). Further, the drilling
process involved the use of a drilling fluid, or mud.
[0047] There are three main categories of drilling fluids:
water-based muds, non-aqueous muds, and gaseous drilling fluids.
Non-aqueous muds, sometimes referred to as non-aqueous fluids
(NAFs), are muds wherein usually the base fluid is an oil or
hydrocarbon-based fluid composition. Environmental considerations
aside, NAFs are often preferred over water-based muds and gaseous
drilling fluids, as NAFs generally offer increased lubrication of
the drill string and drill bit. This is particularly advantageous
in deviated and horizontal drilling operations where the drill
string is forced to slide within and rotate upon the wellbore wall.
In these situations, the non-aqueous-based fluid provides a slick
film along which tubular bodies and equipment may glide while
moving across non-vertical portions of the wellbore.
[0048] NAFs also help stabilize shale and salt formations more
effectively than do water-based or gaseous muds. NAFs also
withstand greater heat without breaking down, and beneficially tend
to form a thinner filter cake than water-based muds.
[0049] The filter cake from a NAF is comprised primarily of water
droplets, weighting agent particles, and drilled cuttings
previously suspended in the drilling mud. The filter cake forms a
thin, low-permeability layer along permeable portions of the
borehole. Beneficially, the filter cake at least partially seals
permeable formations exposed by the bit. This helps prevent the
loss of the liquid portion (or filtrate) of the drilling fluids
into the formations during the wellbore forming process. The filter
cake also helps prevent the surrounding rock matrix from sloughing
into the wellbore. Of note, the drilling process can be ongoing for
days or even weeks.
[0050] A low-permeability filter cake is also desirable for running
completion equipment in the wellbore. For example, it is sometimes
desirable to run the completion hardware in a clear brine to
prevent solids plugging of a sand control screen. The filter cake
prevents the completion brine from rapidly leaking off to the
formation as the completion hardware is run. In addition, a
low-permeability filter cake helps prevent the gravel used in a
gravel pack from bridging off during gravel placement due to a loss
of hydration in the slurry.
[0051] For an injection well however, the wellbore filter cake
issues may or may not be as large of a concern as with production
wells, depending upon the desired injection use. Injection of fluid
below the fracture pressure typically requires removal of the
filter cake to establish injection fluid permeability from the
wellbore face into the formation matrix, along the axial length of
the wellbore injection interval. However, for an injection well
operating above the formation fracture pressure, the created
fracture will typically extend through the drilling filter cake and
into the formation. Injection above fracture pressure is more
typical of a well for disposal of drilling fluids containing solid
particles. However, subsequently created filter cakes within the
injection fracture face may still be a concern by adversely
affecting the desired leak-off properties. This disclosure provides
an improved method and system for injection of solids-containing
non-aqueous fluid slurry, especially such as may be useful for
reinjection of cuttings from a non-aqueous drilling operation.
[0052] In the well site 100 of FIG. 1, an original,
drilling-derived filter cake is illustrated at 162 lining a wall
164 of the open-hole portion of the wellbore 150, adjacent and
adhered to the subsurface formation 160. The filter cake comprises
a NAF fluid.
[0053] Typically, there are two general categories of NAF fluids:
oil-based muds (OBMs) and synthetic-based muds (SBMs). Common
examples of base fluids for an OBM are diesel, mineral oil, or
sometimes produced crude may be used. SBMs may use synthetic oil
rather than a natural hydrocarbon as the base fluid. An example of
a base fluid for a SBM is palm oil. SBMs are most often used on
offshore rigs as SBMs have the beneficial properties of an OBM, but
lower environmental toxicity or flammability. This is of benefit
when the drilling crew is working in an enclosed area, as may be
the case on an offshore drilling rig operating in an arctic
environment.
[0054] The drilling fluid used for a particular job is generally
selected to avoid formation damage. For example, in various types
of shale formations, the use of conventional water-based muds can
result in a deterioration and collapse of the formation. Similarly,
muds made from fresh water can cause clays in a sandstone or other
type formation to swell and dislodge. This, in turn, can negatively
affect the permeability of the sandstone near the wellbore. The use
of an oil-based formulation circumvents these problems.
[0055] As noted, a conventional oil-based drilling mud formulation
is comprised basically of hydrocarbon based oil. Examples of oil
include diesel oil and mineral oil. An OBM may also include a
thickener, or "viscosification agent." Examples of viscosification
agents are amine-treated clays such as bentonite. Neutralized
sulfonated ionomers have also been proposed as viscosification
agents. An OBM may also include a wetting agent.
[0056] A NAF will also include a water phase. This typically
represents sodium chloride or calcium chloride brine. The NAF will
also then include a surfactant as an emulsifying agent. An example
of a surfactant is an alkaline soap of fatty acids. The surfactant
aids in blending the base oil with the brine and stabilizing the
continuous oil emulsion. Finally, a weighting agent may be used. An
example of a weighting agent is barite or barium sulfate. The
presence of both aqueous and nonaqueous fluids and a surfactant
creates an emulsion. The oil/water ratio in the liquid phase is
commonly in the range of 60/40 to 98/2, or more commonly 70/30 to
90/10. NAF drilling fluids, whether oil based or synthetic based,
are also known as invert emulsion systems, as they have an oil or
synthetic base fluid as the external or continuous phase and water
as the internal phase.
[0057] An entire science has developed around producing beneficial
filter cake properties. Filter cake properties include cake
thickness, toughness, slickness, spurt-loss rates, and permeability
at various stages or time. Such properties are important as the
cake that forms on permeable regions of a wellbore can be
beneficial to an operation, or may be detrimental to an operation.
For example, the problems that a filter cake may present include
reduced permeability during production and/or injection operations.
This includes reduced permeability during a drill cuttings
re-injection operation.
[0058] Many publications and inventions have been directed to the
creation and destruction of filter cakes. Exemplary teachings known
in the art include the use of chelating agents to extract metallic
weighting agents from filter cakes, the use of acidic treatment
fluids to dissolve the filter cake elements, and/or the use of
surfactants to clean the filter cake from the surface of a
wellbore. Exemplary publications of such teachings may be found in
U.S. Pat. Publ. No. 2008/0110621, which is incorporated herein in
its entirety by reference. Other exemplary related publications may
be found in U.S. Pat. No. 5,909,774; U.S. Pat. No. 6,631,764; U.S.
Pat. No. 7,134,496; U.S. Pat. Publ. No. 2007/0029085, U.S. Pat.
Publ. No. 2008/0110618; and in Lirio Quintero, et al, Single-phase
Microemulsion Technology for Cleaning Oil or Synthetic-Based Mud,
2007 AADE National Technical Conference (Apr. 10-12, 2007).
[0059] As noted above, filter cakes formed from non-aqueous muds
tend to have a lower permeability and thinner filter cake than
water-based filter cakes. This reduced permeability is beneficial
while the wellbore is being formed. However, filter cakes formed
from an oil-based or synthetic oil-based drilling mud are more
difficult to remediate in preparation for putting a well on
production or injection. Remediation of the filter cake is
challenging, often necessitating complex treatment fluids and
processes. While previously known solutions provided some level of
remediation, the conventional approaches remain relatively costly
and complex. Accordingly, a need exists for an improved method for
remediating NAF filter cake or controlling undesirable buildup of
an NAF filter cake during injection of a NAF, particularly for the
purpose of improving drill cuttings re-injection operations.
[0060] Returning to FIG. 1, fractures 165 are shown extending away
from the wall 164 of the wellbore 150. The fractures 165 have been
formed by injecting drill cuttings as part of a slurry. The
fractures extend through the "drilling-created" filter cake 162 and
into the formation. During reinjection operations of a NAF with
drill-cuttings, the NAF will tend to undesirably tend to build up a
filter cake within the formation fracture face.
[0061] Methods and compositions are proposed herein for teaching
preparation of injectable slurry containing the cutting solids and
an NAF component within the slurry, for use such as in reinjecting
drill cuttings or other solid particulates into an earthen
formation. Typically, the solids or cuttings are recovered from a
NAF drilling cuttings returns fluid stream, such as from a
flow-line at the rig or from a cuttings processing unit that grinds
and treats the cuttings in preparation for disposal.
[0062] A method, composition, and system is disclosed include
obtaining or preparing a slurry-forming fluid, the slurry-forming
fluid comprising water, a viscosifying water soluble polymer, and
an oily solids aggregator. The solid particles may be mixed with
the slurry subsequent to combining these components or in
conjunction with combining the components to create an injectable
slurry. The injectable slurry, including the solids intended for
disposal, is introduced into a wellbore for injection into a
subsurface formation. Typically introduction into the wellbore is
accomplished by pumping the composition at pressure sufficient to
create or exceed fracture pressure of the formation. The formation
may include one or multiple fracture or fracture intervals or
zones, and the fracture may include simple or complex array of
fracture planes, both artificially induced and naturally existing
within the formation.
[0063] According to the present methods, compositions, and systems,
the oily solids aggregator comprises two water soluble polymers.
One is a water soluble polymer that is useful for increasing the
viscosity of the water, typically a salt-containing water, to a
viscosity level sufficient for suspending and transporting the
solids within the pumping system and wellbore. Gel strength is an
optional consideration if desired and may be created if necessary,
but most disposal fluid systems do not require significant gel
strength. The viscosity required is typically no different from a
viscosity range as commonly known for use in reinjecting
cuttings.
[0064] Any water soluble polymer capable of increasing the
viscosity of water can be used to form the viscosifying component
of the injectable slurry. One exemplary polymer group is a
polysaccharide polymer. A useful polysaccharide polymer is a
xanthan polymer. Another useful polymer is carboxyl-methylcellulose
(CMC). Other exemplary polymers may include one or more of a
polysaccharide, guar gum, xanthan, alginate, pectin, cellulosic
polymer, and a viscosifying hydrocolloid. The slurry composition
may include the viscosifying water soluble polymer concentration
typically in the range of 0.1 to 2 wt % based on the weight of the
slurry composition, or in some applications an effective range may
be from 0.1 to 1.0 wt %, while in other applications a useful
concentration may be from 0.2 to 0.5 wt % based on the weight of
the slurry composition. However, these ranges are merely exemplary
and the appropriate viscosifying polymer concentration will depend
upon the desired slurry viscosity for the application being
considered and the type of viscosifying polymer being used. Such
preparations for viscosifying water, including salt water, are
generally known in the art.
[0065] The other water soluble polymer that must be present in the
disclosed compositions and methods is the oily solids aggregator
polymer. This polymer is a key component of the compositions and
methods described herein. The oily solids aggregator polymer is
typically an ionic hydrocolloid polymer that is water soluble in
salt water that aggregates the solids within the NAF fluid into
clumps. The aggregated NAF fluid-solid clumps are typically larger
in mean diameter than the mean opening size or pore diameter size
in the formation. Thereby, the clumped solid conglomerate is
intercepted at the formation fracture face, wellbore borehole face,
and/or perforation channel face, and cannot enter the formation
pores and plug off the formation permeability and prevent the
desired fluid leak-off into the formation. It is desirable to
enable the liquid phase of the injected slurry to leak-off into the
formation, such that the solids phase, in this case the
conglomerated solids, remain within the fracture planes and not
enter the formation pores. Thereby, the volumetric size of the
fracture planes and widths need substantially only be large enough
to accommodate the injected solids and not have to accommodate both
the injected solids and liquids. Typically, the water soluble
polymer is a water soluble ionic polymer, such as hydrolyzed
polyacrylamide (HPAM) polymer, sulfonated polystyrene polymer, and
mixtures thereof.
[0066] The oily solids aggregator aggregates the 0.2 to 50 micron
size oily solid particles that present in the injectable slurry,
wherein the size is with reference to a longest axis through a
particulate. A more commonly encountered solid particulate size
range in reinjected drill cuttings are particulates within the 0.5
to 30 micron size range of oily solids present in the NAF drilling
mud. The obtained solids particulates are aggregated in clumps,
conglomerates, or aggregates (collectively conglomerates) of sizes
of at least 40 microns, and preferably at least 50 microns in
three-dimensional mean diameter or greater. Aggregates of size 40
micron and greater are commonly large enough so as not to enter
common formation pore sizes or plug off formation pore and
permeability, especially aggregates of 50 micron or greater.
Thereby, permeability to the cutting slurry fluid is retains such
that the aggregates may build up and bridge on the formation face,
while permitting the slurry fluids to pass through the solids
bridge and enter the formation pores for dissipation therein.
Reservoir pore plugging due to oily solids of less than 50 micron
mean diameter entering the formation pores and permeability
channels is largely inhibited or prevented, such that rapid
"leak-off" or filtration of the slurry water occurs. This leads to
effective drill cuttings reinjection disposal of mixtures of drill
cuttings and NAF drilling muds.
[0067] In many applications, the injectable slurry composition
comprises from 50 to 80 wt % water, or from 60 to 70 wt % water,
based on the total weight of the injectable slurry composition. In
many applications, the water will also comprise salt, commonly at
least about 0.5 wt % (5 ppt) salt. The salt may include at least
one of a dissolved chloride or bromide of at least one of sodium,
potassium, calcium, and magnesium.
[0068] The slurry forming fluid comprises a mixture or composition
comprising at least the water, and the two polymers (the
viscosifying water soluble polymer and the ionic water soluble
polymer). The injectable slurry composition comprises the slurry
forming fluid and the solid particles. The injectable slurry
composition includes from 15 to 50 wt % solid particles or "solids"
(solid particulates, including drill cuttings and other
particulates), or from 20 to 40 wt % solids, or from 20 to 30 wt %
solids, based on the total weight of the slurry composition.
[0069] A substantial portion, if not all of the solids are obtained
from a drilling fluid returns stream, such as at a drilling rig,
wherein the drilling fluid comprises an NAF. The objective of the
teaching herein pertains to managing the solid particulates in the
presence of an NAF for reinjection or disposal. In many
applications, the collected solid particulates have generally have
not been processed to remove the NAF that coats the particles or is
otherwise associated with the recovered solids, such as forming a
mixture with the recovered solids. In other applications, the
collected solid particulates may have been processed to remove the
NAF that coats or is associated with the recovered solids. In the
event where the recovered solids had been processed to remove the
NAF coating and/or associated NAF fluid, then re-addition of an NAF
to either the slurry forming fluid or to the injectable slurry may
be necessary to enable the desirable clumping or coalescing of the
smaller solid particulates into the aggregates or clumps of at
least forty micron is mean diameter in order to prevent entry of
the small solids into the formation pores.
[0070] Generally, the injectable slurry should comprise from 1 to
30 wt % of NAF, or from 5 to 25 wt % NAF, or from 5 to 20 wt % NAF
to enable aggregation or clumping of the solid particulates by the
ionic water soluble polymer. Typical concentrations of the
non-aqueous fluid are about 10 wt %, but may vary more widely in
some applications. The injectable slurry containing the NAF
component may for ease of distinction from the comparative
aqueous-only injectable slurry fluid compositions, be referred to
herein as an NAF composition even though the actual NAF
concentration is less than 30 wt %, or even less than 15 wt %.
[0071] Hydrolyzed polyacrylamide (HPAM), a commercially available
polymer is used to demonstrate the invention as the oily solids
aggregator. HPAM is an ionic water soluble polymer whose polymer
conformation or shape is sensitive to salt concentration. At low
salt concentration, HPAM functions as an aqueous viscosifier,
particularly due to non-aligned interlocking of the substantially
linear polymer chains. However, at higher salt concentrations, such
as at least 0.5 wt % (brackish water), and more particularly at
least concentrations of at least 3 to 5 wt % (saline water) or at
least 3.5 wt % (typically salinity of seawater), or greater than 5
wt % (brine) up to 26 wt % (saturated brine), the HPAM polymer
chains tend to coil up. When the ionically reactive HPAM polymer
chains coil up in the presence of salt, they pull apart from each
other and lose their viscosifying ability to interlock or crosslink
with each other and the aqueous viscosification effect is lost. For
this reason, the second water soluble viscosifying polymer is often
present to provide viscosification while the ionically reactive
polymer provides the desired aggregation of the solids. Thereby,
the ionically reactive polymer serves as oily solids aggregator.
The viscosifying polymer is preferably a polymer that is less
ionically reactive than the ionically reactive, oily solids
aggregator polymer.
[0072] The ionically reactive, oily solids aggregator polymer
beneficially alters the interfacial properties (such as surface
tension) between the solids, the water, and the NAF, resulting in
clumping and aggregating of the solids into the NAF. The coiled
HPAM functions well as an oily solids aggregator. This unique
feature enables use of HPAM and related or other ionically reactive
water soluble polymer polymers in this invention. Sulfonated
polystyrene is another ionically reactive polymeric additive that
can function as an oily solids aggregator. In broad terms, water
soluble ionic polymers of suitable molecular weight can be used to
prepare slurry compositions of the disclosed invention in the
presence of salt within the water.
[0073] The oily solids aggregator concentration is a function of
water salinity of the injectable slurry and functionality of the
particular oil solids aggregator, which in these examples is a
water soluble polymer that is ionically responsive to salt
concentration and which beneficially alters the wettability or
interfacial tension properties among the various liquid and solid
phases. However, maximum concentrations will not exceed 5 wt %. The
HPAM polymer and sulfonated polystyrene polymer are two examples of
such polymers.
[0074] The oily solids aggregator of the current disclosure may be
present in the injectable slurry of 0.01 to 5 wt % based on the
total weight of the injectable slurry composition. In other
compositions, the oily solids aggregator may be present in the
range of 0.01 to 1.0 wt % or from 0.05 to 0.5 wt %, based upon the
total weight of the injectable slurry.
[0075] In wellbore injectivity applications that are experiencing
formation plugging or damage or a buildup of an injection filter
cake, a filter cake remediation fluid may also be pumped into the
wellbore. The filter cake remediation fluid may be either pumped
ahead of the injectable slurry, or spotted in the wellbore prior to
pumping the injectable slurry into the wellbore, or combined into
the injectable fluid slurry.
[0076] The following non-limiting Examples illustrate the
invention. High temperature high pressure (HTHP) filtration
experiments were conducted.
[0077] In a comparative experiment, a water-based fluid slurry
composition was prepared using 65 wt % sea water, 0.35 wt %
viscosifying water soluble xanthan polymer, and 34.65 wt % of Rev
Dust. Rev Dust is a trademarked, standard drill cuttings lab model
composition medium commonly used to represent solids drill cuttings
solids. Rev Dust is available from Deluxe Testing Equipment, Inc.,
and comprises crystalline silicas and various other solids. The
slurry composition was pressurized at 500 psig and 200 degrees F.
(98 degrees C.), with a filter medium comprising an aloxide disk
having a permeability of 5D and pore sizes of 20 microns. The
results are plotted in FIG. 2, whereby the filtrate volume is
plotted as a function of time. The slope of the plot is a measure
of resistance to filtration. The data points are plotted with
triangles, and exhibit a slope of 0.052.
[0078] In another comparative Example, the impact of oil based mud
on resistance to filtration is shown in FIG. 3, plotted against the
water based mud from Example 2. In Example 3, an oil based mud
slurry composition, not including an oily solids aggregator
polymer, is tested and illustrated. The oil based mud included 65
wt % sea water, and 0.35 wt % xanthan gum viscosifying polymer, but
only 24.5 wt % Rev Dust solids (about one third less solids than in
the water based mud) and 10.4 wt % oil based mud, with the same
pressure and temperature conditions as used for the water based
mud. In spite of having a lower solids concentration than the water
based mud, the oil based mud data points plotted with squares
exhibits a slope of 0.1031, which is about twice the resistance to
filtration as compared to the water based mud. This conclusion
suggests that with inclusion of the oil based mud, the solids must
be effectively plugging the filter pores.
[0079] To understand the reason for the increased resistance to
filtration, slurry viscosity was determined for each of the two
slurries described in FIG. 3, and are graphed in FIG. 4. About a
10,000 cP increase in viscosity is observed when oil based mud
(OBM) is included in the still primarily aqueous based slurry. In
this case only 10.4 wt % OBM was added to the injectable slurry,
but that was enough to substantially, adversely affect injectivity,
as reflected in FIG. 3.
[0080] Optical micrographs of the two slurries were also recorded
(not illustrated). The water based Rev Dust slurry exhibited a
gel-like microstructure, while the water-based slurry containing
the oil based component slurry (referred to herein merely as the
oil based slurry for convenience) exhibited phase separation and
dispersion of the oily solids within and throughout the Rev
Dust+OBM slurry. Further and most concerning, the phase separated
and dispersed oily solids are finely and widely dispersed inside
the phase separated domains. Also, X-Ray absorption cross-section
images of the filter frits were recorded through which each the two
slurries were filtered. It was observed that the OBM solids invade
the pores of the filter and cause plugging. About a 100 micron
thick plugged layer of OBM solids is observed in the X-ray image on
a cross-sectional view of the filter frits. It was inferred that
pore plugging by fine particulates leads to increased resistance to
filtration.
[0081] Exemplary testing: It was hypothesized from the comparative
examples discussed above, that a large clump or aggregation of the
small solids into a size that was larger than the pore size or pore
throat diameter.
[0082] Exemplary testing: As discussed previously above, a core
tenet of the current teaching is to aggregate the oily solids of
the oil based mud such that the aggregates are too large to enter
the formation pores, thus impeding pore plugging by the solids.
This aggregation is achieved by using an oily solids aggregator
additive. The oily solids aggregator additive aggregates the oily
solids and is compatible with the xanthan gum polymer.
[0083] Hydrolyzed polyacrylamide (HPAM), a commercially available
polymer was used to demonstrate the principles disclosed herein. As
discussed above, HPAM is an ionic water soluble polymer having a
polymer conformation that is sensitive to salt concentration. At
low salt concentration, HPAM polymer chains are relatively straight
and elongated, interlacing with the other HPAM polymer chains and
functions as a aqueous viscosifier. At higher salt concentration,
the HPAM polymer chains tend to coil remain largely independent of
the adjacent HPAM polymer chain, such that and the aqueous
viscosification effect is lost. We observed that the coiled HPAM
can function as an oily solids aggregator. This unique feature and
new observation enables use of HPAM in this invention. Sulfonated
polystyrene is another polymeric additive that behaves similarly as
HPAM and can also function as an oily solids aggregator. In broad
terms, water soluble ionic polymers can be used to prepare slurry
compositions of the disclosed techniques.
[0084] In an exemplary demonstration, a new slurry composition was
prepared wherein 0.05 wt % of HPAM oily solids aggregator polymer
was included in the base oil based mud composition that was plotted
previously in comparative plots of FIG. 3. The exemplary
composition included Rev Dust+OBM and xanthan gum polymer slurry,
otherwise using the same concentrations and test conditions as in
the base comparative tests. The viscosity results of the exemplary
composition comprising the oily solids aggregator are plotted in
FIG. 5, and against the two previous base plots that did not
include the oily solids aggregator. Only a small reduction in
viscosity was noticed due to the presence of the non-viscosifying
HPAM polymer as compared to the base comparative oil based mud
composition. However, the slope (resistance to filtration)
decreased substantially from 0.103 with the comparative oil-based
mud composition to 0.065 with the addition of the oily solids
aggregator HPAM polymer. The data points for the injectable slurry
composition comprising the oily solids aggregator is reflected with
diamonds. Though not as permeable as the comparative water based
fluid slurry composition, addition of the oily solids aggregator
pushed the performance of the previously troublesome oil based
fluid slurry composition much closer to that of a water-only based
slurry. Such performance is a welcomed improvement for disposing of
non-aqueous based solids and drill cuttings from an NAF drilling
fluid.
[0085] X-ray absorption photos were taken (not shown) of the filter
frit cross-sections for the exemplary composition containing the
oily solids aggregator and reflected virtually no invasion of the
solids particulates into the pores of the filter frits. Pore
plugging prevention was clearly exhibited, affirming the desirable
performance of the aggregating slurry compositions and methods
disclosed herein. The majority of the solids particles were
observed to be collected substantially exclusively on the surface
of the filter frit. Also, photomicrographs of the injectable fluid
slurry were taken (not shown), wherein the solid particulates were
largely observed to be aggregated into clumps of oil solids, most
having a mean cross-sectional diameter in excess of 40 microns and
even in excess of 50 microns.
INDUSTRIAL APPLICABILITY
[0086] The systems and methods disclosed herein are applicable to
the oil and gas industries. It is believed that the disclosure set
forth above encompasses multiple distinct inventions with
independent utility. While each of these inventions has been
disclosed in its preferred form, the specific embodiments thereof
as disclosed and illustrated herein are not to be considered in a
limiting sense as numerous variations are possible. The subject
matter of the inventions includes all novel and non-obvious
combinations and subcombinations of the various elements, features,
functions and/or properties disclosed herein. Similarly, where the
claims recite "a" or "a first" element or the equivalent thereof,
such claims should be understood to include incorporation of one or
more such elements, neither requiring nor excluding two or more
such elements.
[0087] It is believed that the following claims particularly point
out certain combinations and subcombinations that are directed to
one of the disclosed inventions and are novel and non-obvious.
Inventions embodied in other combinations and subcombinations of
features, functions, elements and/or properties may be claimed
through amendment of the present claims or presentation of new
claims in this or a related application. Such amended or new
claims, whether they are directed to a different invention or
directed to the same invention, whether different, broader,
narrower, or equal in scope to the original claims, are also
regarded as included within the subject matter of the inventions of
the present disclosure.
* * * * *