U.S. patent application number 13/927714 was filed with the patent office on 2015-01-01 for reducing sugar-based sulfide scavengers and methods of use in subterranean operations.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Cato Russell McDaniel.
Application Number | 20150000984 13/927714 |
Document ID | / |
Family ID | 52114505 |
Filed Date | 2015-01-01 |
United States Patent
Application |
20150000984 |
Kind Code |
A1 |
McDaniel; Cato Russell |
January 1, 2015 |
REDUCING SUGAR-BASED SULFIDE SCAVENGERS AND METHODS OF USE IN
SUBTERRANEAN OPERATIONS
Abstract
Improved methods and additives for eliminating or reducing
concentrations of hydrogen sulfide or soluble sulfide ions for use
in subterranean formations and fluids are provided. In one
embodiment, the methods comprise: providing a treatment fluid
comprising a base liquid and a sulfide scavenging additive
comprising one or more reducing sugars; introducing the treatment
fluid into at least a portion of a subterranean formation; and
allowing at least a portion of the sulfide scavenging additive to
interact with hydrogen sulfide or sulfide ions present in the
treatment fluid to produce a precipitate comprising one or more
sulfur species.
Inventors: |
McDaniel; Cato Russell;
(Montgomery, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
52114505 |
Appl. No.: |
13/927714 |
Filed: |
June 26, 2013 |
Current U.S.
Class: |
175/64 |
Current CPC
Class: |
E21B 21/06 20130101 |
Class at
Publication: |
175/64 |
International
Class: |
E21B 21/00 20060101
E21B021/00 |
Claims
1. A method comprising: providing a treatment fluid comprising a
base liquid and a sulfide scavenging additive comprising one or
more reducing sugars; introducing the treatment fluid into at least
a portion of a subterranean formation; and allowing at least a
portion of the sulfide scavenging additive to interact with
hydrogen sulfide or sulfide ions present in the treatment fluid to
produce a precipitate comprising one or more sulfur species.
2. The method of claim 1 wherein the base liquid comprises an
aqueous liquid.
3. The method of claim 1 wherein the treatment fluid comprises a
basic solution.
4. The method of claim 1 wherein the treatment fluid is
substantially free of aldehydes other than aldehydes formed by the
reducing sugars dissolved in the basic solution.
5. The method of claim 1 wherein the pH of the treatment fluid is
above 8.
6. The method of claim 1 wherein one or more metal ions is chelated
with the one or more reducing sugars.
7. The method of claim 6 wherein the one or more metal ions
interact with the hydrogen sulfide or sulfide ions to produce a
precipitate comprising one or more metal sulfides.
8. The method of claim 1 wherein the sulfide scavenging additive
comprises ferric fructose.
9. The method of claim 1 further comprising adding an additional
amount of a sulfide scavenging additive comprising one or more
reducing sugars to the treatment fluid after the treatment fluid
has been introduced into at least a portion of a subterranean
formation.
10. The method of claim 1 wherein: the treatment fluid comprises a
drilling fluid; and the method further comprises using the drilling
fluid to drill at least a portion of a well bore penetrating at
least a portion of the subterranean formation.
11. A method comprising: providing a treatment fluid comprising a
base liquid and a sulfide scavenging additive comprising one or
more reducing sugars chelated with one or more metal ions;
introducing the treatment fluid into at least a portion of a
subterranean formation; allowing at least one of the metal ions to
interact with hydrogen sulfide or sulfide ions present in the
treatment fluid to produce a first product comprising one or more
metal sulfides; and allowing the reducing sugar to interact with
hydrogen sulfide or sulfide ions present in the treatment fluid to
produce a second product comprising one or more sulfur species.
12. The method of claim 11 wherein the base liquid comprises an
aqueous liquid.
13. The method of claim 11 wherein the pH of the treatment fluid is
above 8.
14. The method of claim 11 wherein the sulfur species in the second
product are different from the metal sulfides in the first
product.
15. The method of claim 11 further comprising removing the first or
second products from the treatment fluid in the form of a
precipitate.
16. The method of claim 11 further comprising adding an additional
amount of a sulfide scavenging additive comprising one or more
reducing sugars to the treatment fluid after the treatment fluid
has been introduced into at least a portion of a subterranean
formation.
17. A method of treating a fluid comprising a first concentration
of hydrogen sulfide or sulfide ions, the method comprising: adding
a sulfide scavenging additive comprising one or more reducing
sugars to the fluid; and allowing at least a portion of the sulfide
scavenging additive to interact with at least a portion of the
hydrogen sulfide or sulfide ions in the fluid to reduce the
concentration of hydrogen sulfide or sulfide ions to a second
concentration that is lower than the first concentration.
18. The method of claim 17 wherein the fluid comprises an aqueous
liquid.
19. The method of claim 17 wherein the pH of the fluid is above
8.
20. The method of claim 17 wherein the fluid is present in at least
a portion of a subterranean formation.
Description
BACKGROUND
[0001] The present disclosure relates to fluids, additives, and
methods for use in subterranean operations, and more specifically,
to improved methods and additives for eliminating or reducing
concentrations of hydrogen sulfide or soluble sulfide ions for use
in subterranean formations and fluids.
[0002] Hydrocarbon producing wells may contain many different
formation liquids and gases such as methane, ethane, and other
higher hydrocarbons, as well as hydrogen sulfide, water, and other
compounds. In order to evaluate the commercial value of a
hydrocarbon producing well, or as an aid in operations and well
planning, it is often useful to obtain information by analyzing the
component concentrations of the produced fluid from a formation or
an individual well. Numerous systems have been developed to
evaluate a downhole fluid composition and the relative component
concentrations in the downhole fluid.
[0003] Hydrogen sulfide (H.sub.2S) is a very toxic, flammable, and
pungent gas that causes numerous problems in various aspects of the
oil and gas industry. H2S is extremely corrosive to metal, which
may damage or destroy tubing, casings, or other types of well bore
equipment. H.sub.2S also presents health risks to operations
personnel that may be exposed to H.sub.2S gas at a well site or in
processing of well bore fluids. Severe iron sulfide scaling may
also choke production, either in the production piping,
perforations or within the producing formation itself. Thus, it is
typically desirable to reduce or eliminate sulfides from
subterranean formations and well bores, among other reasons, to
control corrosion rates and to plan for safe development and
production of the hydrocarbons.
[0004] The release of H.sub.25 gas can sometimes be controlled by
maintaining the pH of the fluid containing H.sub.25 above 10.
However, in many cases, it is not practical or possible to maintain
this level pH in a fluid for extended periods of time. Sulfide
scavengers are often used to react with H.sub.25 and convert it to
a more inert form. Conventional H.sub.2S scavengers include certain
aldehydes, certain amine-based chemicals, triazines, copper
compounds, hydrogen peroxide, zinc compounds, and iron compounds.
However, the reaction products of many of these compounds with
H.sub.25 are poorly soluble in treatment fluids and/or fluids in
the well bore, or may decompose, thereby releasing H.sub.2S.
Moreover, many conventional sulfide scavengers themselves may have
undesirable environmental and/or toxicity problems, and as such may
be impractical to use or prohibited altogether in certain
circumstances and/or jurisdictions.
SUMMARY
[0005] The present disclosure relates to fluids, additives, and
methods for use in subterranean operations, and more specifically,
to improved methods and additives for eliminating or reducing
concentrations of hydrogen sulfide or soluble sulfide ions for use
in subterranean formations and fluids.
[0006] In one embodiment, the present disclosure provides a method
comprising: providing a treatment fluid comprising a base liquid
and a sulfide scavenging additive comprising one or more reducing
sugars; introducing the treatment fluid into at least a portion of
a subterranean formation; and allowing at least a portion of the
sulfide scavenging additive to interact with hydrogen sulfide or
sulfide ions present in the treatment fluid to produce a
precipitate comprising one or more sulfur species.
[0007] In another embodiment, the present disclosure provides a
method comprising: providing a treatment fluid comprising a base
liquid and a sulfide scavenging additive comprising one or more
reducing sugars chelated with one or more metal ions; introducing
the treatment fluid into at least a portion of a subterranean
formation; allowing at least one of the metal ions to interact with
hydrogen sulfide or sulfide ions present in the treatment fluid to
produce a first product comprising one or more sulfur species; and
allowing the reducing sugar to interact with hydrogen sulfide or
sulfide ions present in the treatment fluid to produce a second
product comprising one or more sulfur species.
[0008] In another embodiment, the present disclosure provides a
method of treating a fluid comprising a first concentration of
hydrogen sulfide or sulfide ions, the method comprising: adding a
sulfide scavenging additive comprising one or more reducing sugars
to the fluid; and allowing at least a portion of the sulfide
scavenging additive to interact with at least a portion of the
hydrogen sulfide or sulfide ions in the fluid to reduce the
concentration of hydrogen sulfide or sulfide ions to a second
concentration that is lower than the first concentration.
[0009] The features and advantages of the present disclosure will
be readily apparent to those skilled in the art. While numerous
changes may be made by those skilled in the art, such changes are
within the spirit of the disclosure.
BRIEF DESCRIPTION OF THE FIGURES
[0010] Some specific example embodiments of the disclosure may be
understood by referring, in part, to the following description and
the accompanying drawings.
[0011] FIG. 1 illustrates an example of a well bore drilling
assembly that may be used in accordance with certain embodiments of
the present disclosure.
[0012] While the present disclosure is susceptible to various
modifications and alternative forms, specific example embodiments
have been shown in the figures and are herein described in more
detail. It should be understood, however, that the description of
specific example embodiments is not intended to limit the invention
to the particular forms disclosed. On the contrary, this disclosure
is to cover all modifications and equivalents as illustrated, in
part, by the appended claims.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0013] The present disclosure relates to fluids, additives, and
methods for use in subterranean operations, and more specifically,
to improved methods and additives for eliminating or reducing
concentrations of hydrogen sulfide or soluble sulfide ions for use
in subterranean formations and fluids.
[0014] The fluids and sulfide scavenging additives of the present
disclosure generally comprise one or more reducing sugars. The term
"reducing sugar" is defined herein to include any saccharide that
includes an aldehyde functional group or can isomerize to form an
aldehyde functional group in basic solution. In certain
embodiments, the fluids and sulfide scavenging additives of the
present disclosure may be substantially free of compounds having
aldehyde functional group prior to placement in basic solution. In
certain embodiments, the reducing sugar may be chelated with a
metal ion, such as iron. When added to a fluid comprising a liquid,
a chelated reducing sugar may interact with H.sub.2S and/or sulfide
ions present in the fluid to produce one or more sulfur species
(e.g., metal sulfides (such as Fe.sub.2S.sub.3 and FeS) and
elemental sulfur), inter alia, in the form of a precipitate that
can be removed from the liquid. In certain embodiments, this may be
accomplished without further oxidization of the metal ions.
[0015] Among the many potential advantages of the present
disclosure, the methods and compositions of the present disclosure
may, among other things, provide a means of reducing or eliminating
concentrations of hydrogen sulfide or soluble sulfide ions in
fluids found and/or used in subterranean formations with
significantly less risk of environmental damage and/or health and
safety hazards. Such methods and compositions may be more
compatible with regulatory requirements in various jurisdictions.
The sulfide scavenging additives of the present disclosure
comprising one or more reducing sugars may be effective at a wider
range of pH levels (e.g., pH ranges above about 8) than other
sulfide scavenging additives known in the art, and may reduce or
eliminate concentrations of hydrogen sulfide or soluble sulfide
ions in fluids more effectively. The methods and compositions of
the present disclosure also may be more cost effective than other
sulfide scavenging methods and additives known in the art.
[0016] The reducing sugars used in the methods, fluids, and sulfide
scavenging additives of the present disclosure may comprise any
reducing sugar (or combination thereof) known in the art. Such
reducing sugars may comprise monosaccharides, disaccharides,
polysaccharides, and/or combinations thereof. Examples of reducing
sugars that may be suitable for use in certain embodiments of the
present disclosure include, but are not limited to, glucose,
glucosamine, acetyl glucosamine, fructose, sucrose, lactose,
maltose, cellobiose, galactose, mannose, ribose, ribulose, xylose,
lyxose, rhamnose, arabinose, erythrose, and/or combinations
thereof. In certain embodiments, the reducing sugars used in the
methods, fluids, and sulfide scavenging additives of the present
disclosure may have a molecular weight of from about 180 daltons to
about 360 daltons. The reducing sugar optionally may be chelated
with any metal ion known in the art, including but not limited to
iron, zinc, copper, nickel, manganese, and the like. Chelated
reducing sugars that may be suitable for use in certain embodiments
of the present disclosure include, but are not limited to, ferric
fructose, ferrous sucrose, and the like.
[0017] The sulfide scavenging additives used in the present
disclosure may exhibit, among other features, an enhanced ability
to scavenge sulfides as compared to conventional sulfide scavengers
due, at least in part, to the manner in which they react with
sulfides and other components of the fluid. In particular, sulfide
scavenging additives of the present disclosure that comprise one or
more metal ions chelated with reducing sugars may exhibit a dual
sulfide scavenging mechanism wherein the metal ion and the reducing
sugar each interact with hydrogen sulfide or sulfide ions to
produce different products that may be precipitated or otherwise
removed from of the fluid. The interaction of the metal ions with
hydrogen sulfide or sulfide ions may proceed according to one or
more reactions similar those discussed in paragraph [0015] below.
The interaction of the reducing sugar with hydrogen sulfide or
sulfide ions may involve the degradation of the reducing sugar and
the reaction of those degradation products with hydrogen sulfide or
sulfide ions. Alternatively, the reducing sugar may interact with
hydrogen sulfide or sulfide ions to form an intermediate
sulfur-containing compound, the sugar moiety in which may fragment
to form other sulfur containing species. The chelation of the
reducing sugar with the metal ion also may inhibit the conversion
of the metal ion to a metal hydroxide, leaving the metal ion free
to interact with and/or scavenge hydrogen sulfide or sulfide ions
present in the fluid. However, the reaction mechanisms disclosed
herein are provided only as non-limiting illustrations of how the
sulfide scavenging additives of the present disclosure may react in
certain embodiments, and are not intended to limit the scope of the
claims.
[0018] One example of a sulfide scavenging additive that may be
suitable for use in the present disclosure comprises ferric
fructose. In those embodiments, the iron (III) ions in the ferric
fructose may react with hydrogen sulfide to produce iron (III)
sulfide (Fe.sub.2S.sub.3). Additionally, the iron (III) ions may be
reduced by hydrogen sulfide to their iron (II) oxidation state,
producing elemental sulfur (S.sup.0) (see Equation (1) below). The
reduced iron (II) ion may react with additional hydrogen sulfides
to produce iron (II) sulfide (FeS) (see Equation (2) below).
H.sub.2S+2Fe.sup.3+.fwdarw.S.sup.0+2Fe.sup.2++2H.sup.+ (1)
H.sub.2S+Fe.sup.2+.fwdarw.FeS+2H.sup.+ (2)
In this process, the overall result for the ferric ion in this
embodiment of the present disclosure may be expressed according to
Equation (3) below:
2H.sub.2S+2Fe.sup.3+.fwdarw.S.sup.0+2FeS+4H.sup.+ (3)
The elemental sulfur and iron (II) sulfide may form a precipitate
in the fluid being treated, which may be removed from the fluid.
Similar reactions may occur using metallic ions other than iron. In
embodiments where divalent metallic ions are used, elemental sulfur
may not be formed. In addition to the reactions above, the fructose
may interact with hydrogen sulfide or sulfide ions to produce
various sulfur species that may precipitate or be removed from the
fluid being treated.
[0019] The reducing sugar (or chelated reducing sugar) may be added
to or included in a fluid in any concentration that effectively
eliminates or reduces by the desired amount concentrations of
H.sub.2S or sulfide ions that are present or expected to be present
in the fluid. For example, the reducing sugar may be added in a
stoichiometric amount relative to the estimated amount of H.sub.25
or sulfide ions in the fluid. In certain embodiments, the reducing
sugar may be present a fluid in a concentration of about 0.1 to 5
pounds per barrel. As discussed below, an initial amount of the
sulfide scavenging additives of the present disclosure comprising
one or more reducing sugars may be added to a fluid, and
subsequently, additional amounts of the sulfide scavenging
additives of the present disclosure may be added to the same fluid.
This technique may be used, among other purposes, to increase
and/or maintain a concentration of the reducing sugar that is
sufficient to effectively eliminate or reduce by the desired amount
concentrations of H.sub.2S or sulfide ions in the fluid throughout
the course of a given operation.
[0020] The additives of the present disclosure may be used in
conjunction with any fluid, which may include, but are not limited
to, treatment fluids introduced into a subterranean formation as
well as fluids found in a subterranean formation (e.g., formation
water, hydrocarbon fluids, etc.) and/or any combination thereof.
The treatment fluids and formation fluids in the present disclosure
generally comprise a base liquid, which may comprise any liquid
known in the art, such as aqueous liquids, non-aqueous liquids, or
any mixture thereof. Where the base liquid comprises an aqueous
liquid, it may comprise fresh water, salt water (e.g., water
containing one or more salts dissolved therein), brine (e.g.,
saturated salt water), or seawater. Generally, the water can be
from any source, provided that it does not contain compounds that
adversely affect other components of the fluid. Where the base
liquid comprises a non-aqueous liquid, it may comprise any number
of organic liquids. Examples of suitable organic liquids include,
but are not limited to, mineral oils, synthetic oils, esters, and
the like. In certain embodiments, the treatment fluids and/or
formation fluids in the present disclosure may comprise emulsions
(including invert emulsions), suspensions, gels, foams, or other
mixtures of liquids with solids and/or gases.
[0021] The fluids used in the present disclosure optionally may
comprise any number of additional additives, including, but not
limited to, salts, surfactants, acids, fluid loss control
additives, gas, nitrogen, carbon dioxide, surface modifying agents,
tackifying agents, foamers, corrosion inhibitors, scale inhibitors,
catalysts, clay control agents, biocides, friction reducers,
antifoam agents, bridging agents, dispersants, flocculants,
additional H.sub.2S scavengers, CO.sub.2 scavengers, oxygen
scavengers, lubricants, viscosifiers, breakers, weighting agents,
relative permeability modifiers, resins, particulate materials
(e.g., proppant particulates), wetting agents, coating enhancement
agents, and the like. A person skilled in the art, with the benefit
of this disclosure, will recognize the types of additives that may
be included in the fluids of the present disclosure for a
particular application.
[0022] The methods, fluids, and/or additives of the present
disclosure may be used during or in conjunction with any
subterranean operation wherein a fluid is used or treated. In
certain embodiments, the methods, fluids, and/or additives of the
present disclosure may be used in the course of drilling
operations. In these embodiments, the methods, fluids, and/or
additives of the present disclosure may be used to reduce or
eliminate concentrations of H.sub.2S from a drilling fluid used in
drilling a well or borehole, for example, in a hydrocarbon-bearing
subterranean formation where H.sub.2S is often encountered. Other
suitable subterranean operations may include, but are not limited
to, preflush treatments, afterflush treatments, hydraulic
fracturing treatments, sand control treatments (e.g., gravel
packing), acidizing treatments (e.g., matrix acidizing or fracture
acidizing), "frac-pack" treatments, well bore clean-out treatments,
and other operations where a treatment fluid may be useful. Such
treatment fluids may include, but are not limited to, drilling
fluids, preflush fluids, afterflush fluids, fracturing fluids,
acidizing fluids, gravel packing fluids, packer fluids, spacer
fluids, and the like.
[0023] The reducing sugar may be provided in an additive in a solid
form, liquid form (e.g., in solution of water or another solvent),
or a combination thereof. The sulfide scavenging additives of the
present disclosure may be added to a fluid by any means known in
the art. The additive may be added to the fluid, for example, in
the mud pit before the fluid has circulated or before the fluid
contains any detectable amount of sulphur or H.sub.2S, as a
prophylactic measure against any H.sub.2S the fluid may encounter
downhole. In certain embodiments, the additive may be added after
the fluid has been circulating downhole and has already encountered
sulphur or H.sub.2S and contains same. In certain embodiments, the
amount of the additive added to the fluid may be controlled and/or
varied during the course of an operation based on, among other
things, the amount of sulfur or H.sub.2S detected in fluids exiting
the well bore. In these embodiments, any system or technique
capable of monitoring or detecting sulfur or H.sub.2S content in
fluids exiting the well bore may be used. Moreover, the sulfide
scavenging additives of the present disclosure may be added to a
fluid in multiple portions that are added to the fluid at separate
intervals over a period of time. For example, a first amount of a
scavenging additive of the present disclosure may be added to a
fluid at one point in time in the course of a particular operation.
At a subsequent point during that operation, an elevated amount of
sulfur or H.sub.2S may be detected exiting the well bore, at which
point a second amount of a scavenging additive of the present
disclosure may be added to the fluid based at least in part on the
amount of sulfur or H.sub.25 detected.
[0024] The exemplary fluids and additives disclosed herein may
directly or indirectly affect one or more components or pieces of
equipment associated with the preparation, delivery, recapture,
recycling, reuse, and/or disposal of the disclosed fluids and
additives. For example, and with reference to FIG. 1, the disclosed
fluids and additives may directly or indirectly affect one or more
components or pieces of equipment associated with an exemplary
wellbore drilling assembly 100, according to one or more
embodiments. 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.
[0025] 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 borehole 116 that penetrates
various subterranean formations 118.
[0026] A pump 120 (e.g., a mud pump) circulates drilling fluid 122
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 borehole 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 scope of the disclosure.
[0027] One or more of the disclosed additives 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 disclosed additives 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 disclosed additives may be stored, reconditioned, and/or
regulated until added to the drilling fluid 122.
[0028] As mentioned above, the disclosed fluids and additives may
directly or indirectly affect the components and equipment of the
drilling assembly 100. For example, the disclosed fluids and
additives 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 separator, a filter (e.g., diatomaceous
earth filters), a heat exchanger, any fluid reclamation equipment,
The fluid processing unit(s) 128 may further include one or more
sensors, gauges, pumps, compressors, and the like used store,
monitor, regulate, and/or recondition the exemplary fluids and
additives.
[0029] The disclosed fluids and additives may directly or
indirectly affect the pump 120, which representatively includes any
conduits, pipelines, trucks, tubulars, and/or pipes used to
fluidically convey the fluids and additives downhole, any pumps,
compressors, or motors (e.g., topside or downhole) used to drive
the fluids and additives into motion, any valves or related joints
used to regulate the pressure or flow rate of the fluids and
additives, and any sensors (i.e., pressure, temperature, flow rate,
etc.), gauges, and/or combinations thereof, and the like. The
disclosed fluids and additives may also directly or indirectly
affect the mixing hopper 134 and the retention pit 132 and their
assorted variations.
[0030] The disclosed fluids and additives may also directly or
indirectly affect the various downhole equipment and tools that may
come into contact with the fluids and additives 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 fluids and additives 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 fluids and additives 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.
[0031] While not specifically illustrated herein, the disclosed
fluids and additives may also directly or indirectly affect any
transport or delivery equipment used to convey the fluids and
additives to the drilling assembly 100 such as, for example, any
transport vessels, conduits, pipelines, trucks, tubulars, and/or
pipes used to fluidically move the fluids and additives from one
location to another, any pumps, compressors, or motors used to
drive the fluids and additives into motion, any valves or related
joints used to regulate the pressure or flow rate of the fluids and
additives, and any sensors (i.e., pressure and temperature),
gauges, and/or combinations thereof, and the like.
[0032] Therefore, the present disclosure 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 disclosure 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 or modified
and all such variations are considered within the scope and spirit
of the present disclosure. 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. If there is any conflict in the usages
of a word or term in this specification and one or more patent or
other documents that may be incorporated herein by reference, the
definitions that are consistent with this specification should be
adopted.
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