U.S. patent application number 13/899062 was filed with the patent office on 2014-07-31 for precipitated particles and wellbore fluids and methods relating thereto.
The applicant listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Jay Deville, Dale E. Jamison, Charles Landis, Cato McDaniel.
Application Number | 20140209393 13/899062 |
Document ID | / |
Family ID | 51221728 |
Filed Date | 2014-07-31 |
United States Patent
Application |
20140209393 |
Kind Code |
A1 |
Jamison; Dale E. ; et
al. |
July 31, 2014 |
Precipitated Particles and Wellbore Fluids and Methods Relating
Thereto
Abstract
Precipitated mineral particles may provide for wellbore fluids
with tailorable properties and capabilities. Such wellbore fluids
may be included as a portion of a wellbore drilling assembly that
includes a pump in fluid communication with a wellbore via a feed
pipe; and a wellbore fluid disposed in at least one selected from
the group consisting of the pump, the feed pipe, the wellbore, and
any combination thereof, wherein the wellbore fluid has a density
of about 7 ppg to about 50 ppg and comprises a base fluid and a
plurality of precipitated particles having a shape selected from
the group consisting of ovular, substantially ovular, discus,
platelet, flake, toroidal, dendritic, acicular, spiked with a
substantially spherical or ovular shape, spiked with a discus or
platelet shape, rod-like, fibrous, polygonal, faceted, star-shaped,
and any hybrid thereof.
Inventors: |
Jamison; Dale E.; (Houston,
TX) ; Landis; Charles; (Houston, TX) ;
Deville; Jay; (Houston, TX) ; McDaniel; Cato;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
51221728 |
Appl. No.: |
13/899062 |
Filed: |
May 21, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13752697 |
Jan 29, 2013 |
|
|
|
13899062 |
|
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Current U.S.
Class: |
175/217 |
Current CPC
Class: |
E21B 43/267 20130101;
C09K 8/03 20130101; E21B 21/003 20130101; E21B 21/00 20130101 |
Class at
Publication: |
175/217 |
International
Class: |
E21B 21/00 20060101
E21B021/00 |
Claims
1. A wellbore drilling assembly comprising: a pump in fluid
communication with a wellbore via a feed pipe; and a wellbore fluid
disposed in at least one selected from the group consisting of the
pump, the feed pipe, the wellbore, and any combination thereof,
wherein the wellbore fluid has a density of about 7 ppg to about 50
ppg and comprises a base fluid and a plurality of precipitated
particles having a shape selected from the group consisting of
ovular, substantially ovular, discus, platelet, flake, toroidal,
dendritic, acicular, spiked with a substantially spherical or
ovular shape, spiked with a discus or platelet shape, rod-like,
fibrous, polygonal, faceted, star-shaped, and any hybrid
thereof.
2. The wellbore drilling assembly of claim 1, wherein the wellbore
fluid has a sag control of a density change of less than about 1
ppg over a time of about 10 hours to about 120 hours.
3. The wellbore drilling assembly of claim 1, wherein the
precipitated particles have a specific gravity of about 2.6 to
about 20.
4. The wellbore drilling assembly of claim 1, wherein the
precipitated particles have a specific gravity of about 5.5 to
about 20.
5. The wellbore drilling assembly of claim 1, wherein the
precipitated particles have a median diameter of about 5 nm to
about 100 microns.
6. The wellbore drilling assembly of claim 1, wherein the wellbore
fluid further comprises a plurality of second particles, the second
particles being non-precipitated.
7. The wellbore drilling assembly of claim 6, wherein the
precipitated particles in combination with the second particles
have a multiparticle specific gravity of about 3 to about 20.
8. The wellbore drilling assembly of claim 6, wherein the
precipitated particles in combination with the second particles
have a diameter distribution that has at least one mode with a
standard deviation of about 2% or less of a peak diameter of the
mode.
9. The wellbore drilling assembly of claim 6, wherein the
precipitated particles in combination with the second particles
have a multi-modal diameter distribution.
10. A wellbore drilling assembly comprising: a pump in fluid
communication with a wellbore via a feed pipe; a drill string with
drill bit attached to the distal end of the drill string; and a
wellbore fluid in contact with the drill bit, wherein the wellbore
fluid has a density of about 7 ppg to about 50 ppg and comprises a
base fluid and a plurality of precipitated particles having a shape
selected from the group consisting of ovular, substantially ovular,
discus, platelet, flake, toroidal, dendritic, acicular, spiked with
a substantially spherical or ovular shape, spiked with a discus or
platelet shape, rod-like, fibrous, polygonal, faceted, star-shaped,
and any hybrid thereof.
11. The wellbore drilling assembly of claim 10, wherein the
wellbore fluid has a sag control of a density change of less than
about 1 ppg over a time of about 10 hours to about 120 hours.
12. The wellbore drilling assembly of claim 10, wherein the
precipitated particles have a specific gravity of about 2.6 to
about 20.
13. The wellbore drilling assembly of claim 10, wherein the
precipitated particles have a specific gravity of about 5.5 to
about 20.
14. The wellbore drilling assembly of claim 10, wherein the
precipitated particles have a median diameter of about 5 nm to
about 100 microns.
15. The wellbore drilling assembly of claim 10, wherein the
wellbore fluid further comprises a plurality of second particles,
the second particles being precipitated or non-precipitated.
16. A wellbore drilling assembly comprising: a pump capable of
introducing a fluid into a wellbore via a feed pipe; a fluid
processing unit capable of receiving the fluid from a wellbore via
an interconnecting flow line; and a wellbore fluid disposed in at
least one selected from the group consisting of the pump, the feed
pipe, the wellbore, the interconnecting flow line, the fluid
processing unit, and any combination thereof, wherein the wellbore
fluid has a density of about 7 ppg to about 50 ppg and comprises a
base fluid and a plurality of precipitated particles having a shape
selected from the group consisting of ovular, substantially ovular,
discus, platelet, flake, toroidal, dendritic, acicular, spiked with
a substantially spherical or ovular shape, spiked with a discus or
platelet shape, rod-like, fibrous, polygonal, faceted, star-shaped,
and any hybrid thereof.
17. The wellbore drilling assembly of claim 16, wherein the
wellbore fluid has a sag control of a density change of less than
about 1 ppg over a time of about 10 hours to about 120 hours.
18. The wellbore drilling assembly of claim 16, wherein the
precipitated particles have a specific gravity of about 2.6 to
about 20.
19. The wellbore drilling assembly of claim 16, wherein the
precipitated particles have a specific gravity of about 5.5 to
about 20.
20. The wellbore drilling assembly of claim 16, wherein the
precipitated particles have a median diameter of about 5 nm to
about 100 microns.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation-in-part of and
claims priority to U.S. patent application Ser. No. 13/752,697
filed on Jan. 29, 2013, entitled "Precipitated Particles and
Wellbore Fluids and Methods Relating Thereto," the entire
disclosure of which is incorporated herein by reference.
BACKGROUND
[0002] The present invention relates to precipitated particles and
wellbore fluids and methods relating thereto.
[0003] In the exploration and recovery of hydrocarbons from
subterranean formations, a variety of wellbore operations are
performed, e.g., drilling operations, cementing operations, and
stimulation operations. One physical property of the wellbore
fluids used in conjunction with these wellbore operations is
density. For example during drilling operations, the density of a
wellbore fluid must be carefully controlled so as to exert
sufficient pressure to stabilize the walls of the wellbore, e.g.,
to prevent blowouts, while simultaneously not exerting excess
pressure that can cause damage to the surrounding subterranean
formation. In another example, the density of spacer fluids and
cementing operations must be carefully balanced so as to minimize
or prevent mixing of other wellbore fluids on either side of the
spacer fluid (e.g., a drilling fluid and a cementing fluid).
[0004] Changing the density of wellbore fluids is often achieved
with the use of particles (often referred to in the art as
weighting agents). The characteristics of weighting agent particles
(e.g., specific gravity and particle size distribution) effect not
only the density of the wellbore fluid, but also other wellbore
fluid properties, like sag and viscosity. The ability to tailor the
properties of the weighting agent to achieve desired wellbore fluid
characteristics may allow for reduced cost by minimizing the need
for other additives because the tailored weighting agent can
achieve the desired wellbore fluid characteristics. However, the
grinding process used to produce weighting agents provides little
tailorability in terms of particle characteristics.
[0005] The characteristics of the weighting agent particles (e.g.,
particle shape and particle size distribution) is primarily
determined by the grinding procedure and the composition of the
bulk mineral including any contaminants. In some instances, sieves
can be used to remove at least some of the larger or smaller
particle sizes from the ground material. However, this provides
limited ability to tailor the average particle size and particle
size distribution of the weighting agent particles. Moreover, the
grind process offers no ability to tailor the shape and morphology
of the weighting agent particles. Accordingly, methods that allow
for the production of weighting agents with tailored
characteristics and the methods that employ the resultant wellbore
fluids would be of value to one in the art.
SUMMARY OF THE INVENTION
[0006] The present invention relates to precipitated particles and
wellbore fluids and methods relating thereto.
[0007] One embodiment of the present invention provides for a
wellbore drilling assembly that includes a pump in fluid
communication with a wellbore via a feed pipe; and a wellbore fluid
disposed in at least one selected from the group consisting of the
pump, the feed pipe, the wellbore, and any combination thereof,
wherein the wellbore fluid has a density of about 7 ppg to about 50
ppg and comprises a base fluid and a plurality of precipitated
particles having a shape selected from the group consisting of
ovular, substantially ovular, discus, platelet, flake, toroidal,
dendritic, acicular, spiked with a substantially spherical or
ovular shape, spiked with a discus or platelet shape, rod-like,
fibrous, polygonal, faceted, star-shaped, and any hybrid
thereof.
[0008] Another embodiment of the present invention provides for a
wellbore drilling assembly that includes a pump in fluid
communication with a wellbore via a feed pipe; a drill string with
drill bit attached to the distal end of the drill string; and a
wellbore fluid in contact with the drill bit, wherein the wellbore
fluid has a density of about 7 ppg to about 50 ppg and comprises a
base fluid and a plurality of precipitated particles having a shape
selected from the group consisting of ovular, substantially ovular,
discus, platelet, flake, toroidal, dendritic, acicular, spiked with
a substantially spherical or ovular shape, spiked with a discus or
platelet shape, rod-like, fibrous, polygonal, faceted, star-shaped,
and any hybrid thereof.
[0009] Yet another embodiment of the present invention provides for
a wellbore drilling assembly that includes a pump capable of
introducing a fluid into a wellbore via a feed pipe; a fluid
processing unit capable of receiving the fluid from a wellbore via
an interconnecting flow line; and a wellbore fluid disposed in at
least one selected from the group consisting of the pump, the feed
pipe, the wellbore, the interconnecting flow line, the fluid
processing unit, and any combination thereof, wherein the wellbore
fluid has a density of about 7 ppg to about 50 ppg and comprises a
base fluid and a plurality of precipitated particles having a shape
selected from the group consisting of ovular, substantially ovular,
discus, platelet, flake, toroidal, dendritic, acicular, spiked with
a substantially spherical or ovular shape, spiked with a discus or
platelet shape, rod-like, fibrous, polygonal, faceted, star-shaped,
and any hybrid thereof.
[0010] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] The following figures are included to illustrate certain
aspects of the present invention, 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.
[0012] FIGS. 1A-B illustrate examples of theoretical multi-modal
diameter distributions for particles.
[0013] FIG. 2 illustrates an exemplary wellbore drilling assembly
for use in conjunction with the mineral particles, related fluids,
and related methods described herein.
DETAILED DESCRIPTION
[0014] The present invention relates to precipitated particles and
wellbore fluids and methods relating thereto.
[0015] The present invention provides for, in some embodiments,
precipitated particles that can be used in subterranean
applications as unique weighting agents. Precipitated particle
characteristics like shape and particle size distribution may, in
some embodiments, be tailored during precipitation synthesis, for
example, through pH and/or temperature. Further, precipitation as a
synthesis method may allow for unique shapes and narrow particle
size distributions that can be exploited so as to achieve desired
properties and capabilities in the corresponding wellbore fluids
(e.g., density, viscosity, and sag control). For example, discus or
platelet shaped precipitated particles may increase the viscosity
of a wellbore fluid and settle in the wellbore fluid at a slower
rate, thereby yielding a viscosified fluid with less sag.
[0016] The ability to tailor the properties and capabilities of
wellbore fluids may advantageously allow for the a reduction in
other, potentially expensive and less environmentally-desirable,
additives because the characteristics of the precipitated particles
provide for the desired properties and capabilities of the wellbore
fluid.
[0017] Further, the purity of the precipitated particles may be
utilized to bring mined or ground weighting agents into an
acceptable specification. For example, some grades of mined barite
contain high levels of sand and other particles. Precipitated
particles described herein may be combined with such ground barite
to decrease the overall abrasiveness and increase specific gravity
of the weighting agent additive. In other examples, ground minerals
that are mined in some areas of the world may have higher levels of
heavy metals like mercury or cadmium. The inclusion of the higher
purity precipitated particles may dilute the contaminants to
acceptable levels.
[0018] It should be noted that when "about" is used herein at the
beginning of a numerical list, "about" modifies each number of the
numerical list. It should be noted that in some numerical listings
of ranges, some lower limits listed may be greater than some upper
limits listed. One skilled in the art will recognize that the
selected subset will require the selection of an upper limit in
excess of the selected lower limit.
[0019] It should be noted that unless otherwise specified, the term
"precipitated particles" encompasses single types of precipitated
particles and combinations of more than one type of particle,
including combinations of precipitated particles with
non-precipitated particles. Distinctions between types of
precipitated particles may, in some embodiments, be defined by at
least one of composition, shape, median diameter, aspect ratio,
diameter distribution, presence or absence of coating, coating
composition, and the like, and any combination thereof.
[0020] In some embodiments, the precipitated particles described
herein may be formed by precipitation methods. The precipitation
methods may advantageously yield precipitated particles that have
desired characteristics (e.g., size, shape, diameter distribution,
median diameter, and the like).
[0021] Some embodiments of the present invention may involve
precipitating particles from two or more salts in aqueous solutions
so as to yield the precipitated particles described herein (or
precursors to precipitated particles described herein, e.g.,
particles that can be further calcined to yield precipitated
particles described herein). For example, some embodiments of the
present invention may involve precipitating manganese carbonate
from manganese (II) salts in aqueous solutions with alkali metal
carbonates so as to yield the precipitated manganese carbonate
particles. Examples of other salts that may be used in producing
precipitated particles may include salts (e.g., fluorides,
chlorides, bromides, iodides, acetates, formates, citrates,
sulfates, carbonates, hydroxides, phosphates, silicates,
molybdates, tungstates, vanadates, titanates, chromates, and the
like) of barium, bismuth, chromium, cobalt, copper, gold, iron,
lead, nickel, strontium, tin, zinc, manganese, tungsten, aluminum,
silver, cerium, magnesium, zirconium, titanium, calcium, antimony,
lead, and the like, and any combination thereof.
[0022] In some embodiments, the concentration of salts used in the
formation of precipitated particles may range from a lower limit of
about 1 mM, 10 mM, or 50 mM to an upper limit of about 5 M, 1 M, or
100 mM, and wherein the concentration may range from any lower
limit to any upper limit and encompasses any subset
therebetween.
[0023] In some embodiments, the precipitated particles described
herein that are formed by precipitation methods may comprise at
least one of AgI, AgCl, AgBr, AgCuS, AgS, Ag.sub.2S,
Al.sub.2O.sub.3, AsSb, AuTe.sub.2, BaCO.sub.3, BaSO.sub.4,
BaCrO.sub.4, BaO, BeO, BiOCl, (BiO).sub.2CO.sub.3, BiO.sub.3,
Bi.sub.2S.sub.3, Bi.sub.2O.sub.3, CaO, CaF.sub.2, CaWO.sub.4,
CaCO.sub.3, (Ca,Mg)CO.sub.3, CdS, CdTe, Ce.sub.2O.sub.3, CoAsS,
Cr.sub.2O.sub.3, CuO, Cu.sub.2O, CuS, Cu.sub.2S, CuS.sub.2,
Cu.sub.9S.sub.5, CuFeS.sub.2, Cu.sub.5FeS.sub.4,
CuS.Co.sub.2S.sub.3, Fe.sup.2+Al.sub.2O.sub.4, Fe.sub.2SiO.sub.4,
FeWO.sub.4, FeAs.sub.2, FeAsS, FeS, FeS.sub.2, FeCO.sub.3,
Fe.sub.2O.sub.3, .alpha.-Fe.sub.2O.sub.3, .alpha.-FeO(OH),
Fe.sub.3O.sub.3, FeTiO.sub.3, HgS, Hg.sub.2Cl.sub.2, MgO,
MnCO.sub.3, Mn.sub.2S, MnWO.sub.4, MnO, MnO.sub.2, Mn.sub.2O.sub.3,
Mn.sub.3O.sub.3, Mn.sub.2O.sub.7, MnO(OH), CaMoO.sub.4, MoS.sub.2,
MOO.sub.2, MOO.sub.3, NbO.sub.4, NiO, NiAs.sub.2, NiAs, NiAsS, NiS,
PbTe, PbSO.sub.4, PbCrO.sub.4, PbWO.sub.4, PbCO.sub.3,
(PbCl).sub.2CO.sub.3, Pb.sup.2+.sub.2Pb.sup.4+O.sub.4,
Sb.sub.2SnO.sub.5, Sc.sub.2O.sub.3, SnO, SnO.sub.2, SrO,
SrCO.sub.3, SrSO.sub.4, TiO.sub.2, UO.sub.2, V.sub.2O.sub.3,
VO.sub.2, V.sub.2O.sub.5, VaO, Y.sub.2O.sub.3, YPO.sub.4,
ZnCO.sub.3, ZnO, ZnFe.sub.2O.sub.4, ZnAl.sub.2O.sub.4, ZnS,
ZrSiO.sub.4, ZrO.sub.2, ZrSiO.sub.4, and any combination thereof in
discrete domains and/or a substantially homogeneous domain.
[0024] In some embodiments, combination of more than one salt may
be used to form precipitated particles with two or more of the
foregoing precipitates in substantially homogeneous domain. For
example, strontium and barium salts may be utilized in forming
precipitated particles that comprise (Ba,Sr)SO.sub.4 or
(Ba,Sr)CO.sub.3. In another example, barium salts may be used in
forming precipitated particles that comprise
Ba(SO.sub.4,CrO.sub.4). Examples of other substantially homogeneous
domains may include, but are not limited to, suitable mixtures of
barium, strontium, calcium, zinc, iron, cobalt, manganese, lead,
tin, and the like, and any combination thereof in the form of
sulfates, carbonates, hydroxide, oxides, sulfides, chromates and
the like, and any combination thereof.
[0025] Some embodiments may involve forming precipitated particles
with discrete domains that comprise at least one of the foregoing
precipitates. For example, a calcium carbonate particle may be
formed by precipitation and then barium salts added so as to
precipitate barium carbonate on at least a portion of the surface
of the calcium carbonate precipitated particle. In another example,
a higher specific gravity composition like those comprising bismuth
may be precipitated and then a different composition precipitated
thereon. Precipitating a second composition on a first composition
may allow for the first composition to be formed with a desired
shape and the second composition to increase the specific gravity
of the particle, which may allow for a desired higher specific
gravity particle with a desired shape that may be difficult to
achieve otherwise. In another example, the higher specific gravity
particle may be the first composition and the second composition
precipitated thereon may enable linking of the particles or reduce
the abrasiveness of the particles (described further herein).
[0026] In some embodiments, the particles produced by precipitation
may be calcined to yield precipitated particles described herein.
Calcining may, inter alia, increase the mechanical properties
(e.g., crush strength) of the precipitated particles, yield a
corresponding oxide (e.g., manganese carbonate to manganese oxide,
calcium carbonate to calcium oxide, bismuth carbonate to bismuth
oxycarbonate or bismuth oxide, zirconium hydroxide to zirconium
oxide, or magnesium hydroxide to magnesium oxide), or any
combination thereof.
[0027] In some embodiments, the precipitated particles described
herein may be shaped as spherical, ovular, substantially spherical,
substantially ovular, discus, platelet, flake, toroidal (such as
donut-shaped), dendritic, acicular, spiked with a substantially
spherical or ovular shape (such as a sea urchin), spiked with a
discus or platelet shape, rod-like, fibrous (such as high-aspect
ratio shapes), polygonal (such as cubic or pyramidal), faceted
(such as the shape of crystals), star or floral shaped (such as a
tripod or tetrapod where rods or the like extend from a central
point), or any hybrid thereof (e.g., a dumbbell-shape). For
example, spherical, ovular, substantially spherical, and
substantially ovular-shaped precipitated particles may be useful in
producing wellbore fluids that are less abrasive to wellbore tools
and/or decrease viscosity as compared to ground particles. In
another example, platelet, flake, acicular, spiked with a discus or
platelet shape, rod-like, and fibrous-shaped precipitated particles
may be useful in producing wellbore fluids with less sag and/or
greater viscosity as compared to ground particles.
[0028] It should be noted that as used herein, the terms "median
diameter" and "diameter distribution" refers to a weight median
diameter and a weight diameter distribution, respectively, wherein
the diameter is based on the largest dimension of the particles.
For example, rod-like particles would have diameter distributions
and the like based on the length of the rod-like particles. As used
herein, the term "median diameter" refers to a diameter
distribution wherein 50% of the particles are smaller than a given
value.
[0029] In some embodiments, the precipitated particles described
herein may have a median diameter ranging from a lower limit of
about 5 nm, 10 nm, 20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1
micron to an upper limit of about 100 microns, 50 microns, 25
microns, 10 microns, 5 microns, 1 micron, or 750 nm, and wherein
the median diameter may range from any lower limit to any upper
limit and encompasses any subset therebetween. One of ordinary
skill in the art should understand that precipitation methods may
be used to yield larger sizes of particles that are millimeters or
larger in size. For example, precipitated particles having a median
diameter of about 1-10 mm may be used as proppants or lost
circulation materials.
[0030] In some embodiments, the precipitated particles may be
ground to achieve a desired size and/or shape. Methods that involve
precipitation and then grinding may advantageously allow for
production of higher purity precipitated particles as compared to
particles produced by grinding bulk minerals. Further, such methods
may allow for reduced cost while maintaining high purity as
compared to some precipitation methods with steps to control
particle size. In some instances, larger precipitated particles may
be directly added to a mined mineral and undergo the same grinding
process such that the ground product may have a higher purity than
the mineral alone. For example, large particles of barium sulfate
may formed by precipitation and added to mined barite with high
levels of contaminants (e.g., greater than 15% sand) such that the
ground product is higher purity, which yields a less abrasive,
higher specific gravity weighting agent that is of greater value in
the industry.
[0031] In some embodiments, the precipitated particles may have a
narrow diameter distribution. That is, the diameter distribution
(or at least one mode of a multimodal diameter distribution) may
have a standard deviation of about 2% or less of the peak diameter
for the given mode (e.g., about 0.1% to about 2% or any subset
therebetween). In some embodiments, it is believed that
precipitation methods may be advantageously employed to achieve
narrow diameter distributions of precipitated particles described
herein.
[0032] In some embodiments, the conditions under which the
precipitated particles are formed may be manipulated so as to
assist in controlling or directing the characteristics of the
precipitated particles (e.g., shape, median diameter, diameter
distribution, narrow diameter distribution, density, hardness, and
the like). Examples of conditions that can be manipulated may
include, but are not limited to, pH, temperature, chemical
composition of morphology modifiers, concentration of morphology
modifiers, concentration of the salts used in the production of the
precipitated particles, and the like, and any combination thereof.
For example, increasing the pH and/or temperature may increase the
median diameter of the precipitated particles.
[0033] In some embodiments, forming precipitated particles may be
at a pH ranging from a lower limit of about 2, 3, 4, 5, 7, or 8 to
an upper limit of about 12, 11, 10, 9, 8, 7, or 6, and wherein the
pH may range from any lower limit to any upper limit and
encompasses any subset therebetween.
[0034] In some embodiments, forming precipitated particles may be
at a temperature ranging from a lower limit of about 10.degree. C.,
20.degree. C., 30.degree. C., 40.degree. C., or 50.degree. C. to an
upper limit of about 95.degree. C., 90.degree. C., 80.degree. C.,
70.degree. C., or 60.degree. C., and wherein the temperature may
range from any lower limit to any upper limit and encompasses any
subset therebetween.
[0035] As used herein, the term "morphology modifiers" refers to
chemicals that are used during the formation of precipitated
particles that effect the characteristics of the precipitated
particles. Examples of morphology modifiers may include, but are
not limited to, polymers, surfactants, electrolytes, hydrogen
peroxide, silicates and other similar inorganic materials,
aqueous-miscible organic liquids, and the like, and any combination
thereof.
[0036] Without being limited by theory, it is believed that
morphology modifiers may direct the formation of the precipitated
particles in one of at least two ways. First, the morphology
modifiers may form structures within the precipitation fluid that
direct the growth of the precipitated particle. For example, block
copolymers may form micelles in aqueous solutions (e.g., spherical
micelles, rod-like micelles, worm-like micelles, and the like
depending on, inter alia, concentration and pH) that direct the
growth of the precipitated particles based on the size and shape of
the micelles. Second, the morphology modifiers may interact
directly with various portions of the surface of the precipitated
particles so as to decrease or enhance growth of that portion of
the surface. This may be most prevalent in the formation of
precipitated particles with different crystalline lattice surfaces
(e.g., (101) vs (100) surfaces). For example, the inclusion of
electrolytes like citrate may diminish growth of the precipitated
particle on at least one crystal surface so as to yield
precipitated particles with rod-like or flake shapes.
[0037] In some instances, both of the foregoing factors may be
involved. For example, by varying the acidic groups of the
polyethylene imine (PEI) block of a polyethylene
oxide-co-polyethylene imine (PEO-co-PEI), the shape of the
resultant precipitated particles can be drastically altered, e.g.,
barium sulfate precipitated particles may be dumbbell-shaped when
utilizing PEO-co-PEI-COOH, fibrous or needle-like with
PEO-co-PE.sub.1-PO.sub.3H.sub.2, or floral-shaped with
PEO-co-PE.sub.1-SO.sub.3H as compared to a faceted structure
without the polymer.
[0038] Examples of polymers that may be useful as morphology
modifiers may, in some embodiments, include, but are not limited
to, peptides, PEO-co-PEI-SO.sub.3H, PEO-co-PEI-COOH,
PEO-co-PE.sub.1-PO.sub.3H.sub.2, PEO-co-polypropylene oxide (PPO),
PPO-co-PEO-co-PPO, PEO-co-polyethylene (PE),
PPO-co-poly(methacrylic acid) (PMAA), PEO-co-poly(2-vinylpyridine)
(P2VP), P2VP-co-polyacrylic acid (PAA), PMMA-co-PAA, polystyrene
sulfonate (PSS), PEO, PPO, PE.sub.1, PE.sub.1-SO.sub.3H, PEI-COOH,
PE.sub.1-PO.sub.3H.sub.2, PMAA, and the like, salts thereof where
appropriate, any derivative thereof, and any combination thereof.
Additional examples of polymers that may be useful as morphology
modifiers may, in some embodiments, include, but are not limited
to, homopolymers or copolymers of monomers selected from the group
comprising: acrylic acid, itaconic acid, maleic acid or anhydride,
hydroxypropyl acrylate vinylsulphonic acid, acrylamido 2-propane
sulphonic acid, acrylamide, methacrylamide, hydrolyzed acrylamide,
styrene sulphonic acid, acrylic phosphate esters, methyl vinyl
ether, vinyl acetate, stearyl methacrylate, butylacrylate, vinyl
pyrrolidone, glycols (ethylene glycol, propylene glycol, and
butylene glycol), and the like, salts thereof where appropriate,
any derivative thereof, and any combination thereof. Examples of
commercially available polymers may include Pluronic.RTM.
surfactants (polyethylene oxide-polypropylene oxide-polyethylene
oxide triblock polymers, available from BASF), Tetronic.RTM.
surfactants (tetra-functional block copolymers based on ethylene
oxide and propylene oxide, available from BASF), and the like, and
any combination thereof. In some embodiments, when polymers are
used in the formation of precipitated particles, the resultant
particles may be at least partially coated with the polymers.
[0039] In some embodiments, molecular weight of the polymer may
effect the characteristics of the resultant precipitated particle.
For example, PSS polymers used in the synthesis of precipitated
particles (e.g., carbonate particles) may be more spherical with
higher molecular weight PSS. In some embodiments, the molecular
weight of polymers used as morphology modifiers in the formation of
precipitated particles may range from a lower limit of about 10,000
g/mol, 25,000 g/mol, 100,000 g/mol, or 250,000 g/mol to an upper
limit of about 2,000,000 g/mol, 1,000,000 g/mol, 500,000 g/mol, or
250,000 g/mol, and wherein the molecular weight may range from any
lower limit to any upper limit and encompasses any subset
therebetween.
[0040] In some embodiments, the concentration of polymers used as
morphology modifiers in the formation of precipitated particles may
range from a lower limit of about 0.1 g/L, 1 g/L, or 5 g/L to an
upper limit of about 100 g/L, 25 g/L, 10 g/L, or 5 g/L, and wherein
the concentration may range from any lower limit to any upper limit
and encompasses any subset therebetween.
[0041] Examples of surfactants that may be useful as morphology
modifiers may, in some embodiments, include, but are not limited
to, oleic acid, monobasic fatty acids, polybasic fatty acids,
alkylbenzene sulfonic acids, alkane sulfonic acids, linear
alpha-olefin sulfonic acid, phospholipids, betaines, and the like,
salts thereof where appropriate, any derivative thereof, and any
combination thereof. Examples of commercially available surfactants
may include Brij.RTM. surfactants (ethoxylated fatty alcohols,
available from Sigma-Aldrich), Triton.RTM. surfactants (ethoxylated
fatty alkylphenols, available from Sigma-Aldrich), and the like,
and any combination thereof.
[0042] In some embodiments, the concentration of surfactants used
as morphology modifiers in the formation of precipitated particles
may range from a lower limit of about 0.1 g/L, 1 g/L, or 5 g/L to
an upper limit of about 100 g/L, 25 g/L, 10 g/L, or 5 g/L, and
wherein the concentration may range from any lower limit to any
upper limit and encompasses any subset therebetween.
[0043] Examples of aqueous-miscible organic liquids that may be
useful as morphology modifiers may, in some embodiments, include,
but are not limited to, acetone, dimethyl formamide, methanol,
ethanol, n-propanol, isopropanol, n-butanol, sec-butanol,
isobutanol, t-butanol, glycerol, pyridine, tetrahydrofuran, and the
like.
[0044] In some embodiments, the concentration of aqueous-miscible
organic liquids used as morphology modifiers in the formation of
precipitated particles may range from a lower limit of about 1%,
10%, or 25% by volume of the precipitation fluid to an upper limit
of about 98%, 75%, or 50% by volume of the precipitation fluid, and
wherein the concentration may range from any lower limit to any
upper limit and encompasses any subset therebetween.
[0045] In some embodiments, multiple morphology modifiers may be
manipulated to achieve precipitated particles with desired
characteristics. By way of nonlimiting example, hydrogen peroxide
concentration and pH may be adjusted to change the surface of
precipitated particles, e.g., with respect to calcium carbonate
precipitated particles, higher pH values (e.g., about 11) and
higher hydrogen peroxide concentrations may yield calcium
carbonated precipitated particles with smaller faceted protrusions
(or spikes) on the surface as compared to a lower pH (e.g., about
9) and lower hydrogen peroxide concentrations that may yield
larger, smoother facets along the surface of the precipitated
particle. Further, the precipitation time may be adjusted to allow
for particle fusion to yield dumbbell or peanut-shaped precipitated
particles that depending on the pH and hydrogen peroxide
concentration may have large faceted surfaces or small faceted
protrusions.
[0046] In some embodiments of the present invention, wellbore
additives and/or wellbore fluids may comprise the precipitated
particles described herein. Such wellbore additives and/or wellbore
fluids may be used in conjunction with a plurality of wellbore
operations. As used herein, the terms "wellbore additive" and
"wellbore fluid" refer to any additive or fluid, respectively,
suitable for use in conjunction with a wellbore penetrating a
subterranean formation and does not imply any particular action by
the additive or fluid. Similarly, the term "wellbore operation"
refers to any treatment or operation suitable for use in
conjunction with a wellbore and/or subterranean formation, e.g.,
drilling operations, lost circulation operations, fracturing
operations, cementing operations, completion operations, and the
like.
[0047] In some embodiments, the wellbore additives and/or the
wellbore fluids may comprise the precipitated particles described
herein having a multimodal diameter distribution (e.g., bimodal,
trimodal, and so on). In some embodiments, the wellbore additives
and/or the wellbore fluids may comprise the precipitated particles
described herein having a multimodal diameter distribution such
that at least one mode has an median diameter (or peak diameter)
ranging from a lower limit of about 5 nm, 10 nm, 20 nm, 50 nm, 100
nm, 250 nm, 500 nm, or 1 micron to an upper limit of about 50
microns, 10 microns, 5 microns, 1 micron, or 500 nm and at least
one mode has an median diameter ranging from a lower limit of about
10 microns, 25 microns, 50 microns, or 100 microns to an upper
limit of about 5000 microns, 2500 microns, 1000 microns, 500
microns, 100 microns, or 50 microns, and wherein each mode may
range from any corresponding lower limit to any corresponding upper
limit such that at least two distinct modes are present and each
range encompasses any corresponding subset therebetween. By way of
nonlimiting example, FIGS. 1A-B illustrate theoretical multimodal
diameter distributions for use in wellbore fluids. FIG. 1A
illustrates a bimodal diameter distribution with a first mode
median diameter of about 1 micron and a second mode median diameter
of about 25 microns. FIG. 1B illustrates a trimodal diameter
distribution with a first mode median diameter of about 5 microns,
a second mode median diameter of about 50 microns, and a third mode
median diameter of about 90 microns.
[0048] In some embodiments, the mode(s) of a diameter distribution
may independently be considered to have a narrow diameter
distribution. That is, at least one mode of a diameter distribution
(including monomodal) may have a standard deviation of about 2% or
less of the peak diameter for the given mode (e.g., about 0.1% to
about 2% or any subset therebetween). In some embodiments, it is
believed that precipitation methods may be advantageously employed
to achieve narrow diameter distributions of precipitated particles
described herein.
[0049] The precipitated particles described herein may be added to
a wellbore fluid to achieve a desired density of the wellbore
fluid. In some embodiments, the wellbore fluids described herein
may have a density between a lower limit of about 7 pounds per
gallon ("ppg"), 9 ppg, 12 ppg, 15 ppg, or 22 ppg to an upper limit
of about 50 ppg, 40 ppg, 30 ppg, 22 ppg, 20 ppg, or 17 ppg, and
wherein the density of the wellbore fluid may range from any lower
limit to any upper limit and encompasses any subset therebetween.
One of ordinary skill in the art should understand that the ability
to achieve a desired density of the wellbore fluid while
maintaining a fluid that can be pumped may depend on, inter alia,
the composition and specific gravity of the precipitated particles,
the shape of the precipitated particles, the concentration of the
precipitated particles, and the like, and any combination thereof.
For example, wellbore fluids having a density of about 25 ppg or
higher may be achieved with precipitated particles having a
specific gravity of about 7 or greater (e.g., BiO.sub.3 and/or
Bi.sub.2O.sub.3) and having a shape of spherical, substantially
spherical, ovular, substantially ovular, or a hybrid thereof so as
to allow for the fluid to be pumpable. In another example, wellbore
fluids having a density of about 30 ppg or less may be achieved
with precipitated particles having a specific gravity of about 7 or
greater and having a larger variety of shapes, including
discus.
[0050] In some embodiments, a mixture of two or more types of
precipitated particles (or a mixture of precipitated and
non-precipitated particles) described herein having a multiparticle
specific gravity may be added to a wellbore fluid for a desired
density. As used herein, the term "multiparticle specific gravity"
refers to the calculated specific gravity from Formula I.
multiparticle specific gravity=vol % A*sg.sub.A+vol % B*sg.sub.B+ .
. . vol % n*sg.sub.n Formula I: [0051] wherein vol % is the volume
percent of particle relative to the total volume of the particles
used as weighting agent, sg is the specific gravity of the
particle, A is the first particle, B is the second particle, and n
is the n.sup.th particle
[0052] In some embodiments, the wellbore additives and/or the
wellbore fluids may comprise a mixture of precipitated particles
described herein having a multiparticle specific gravity ranging
from a lower limit of about 3, 4, 4.5, 5, or 5.5 to an upper limit
of about 20, 15, 10, 9, 8, or 7, and wherein the multiparticle
specific gravity may range from any lower limit to any upper limit
and encompasses any subset therebetween. One of ordinary skill in
the art with the benefit of this disclosure should understand that
when specific gravity is referred to in combination with multiple
precipitated particles, specific gravity refers to the
multiparticle specific gravity. In some embodiments, the mixture of
precipitated particles may comprise at least one precipitated
particle and at least one non-precipitated particle (e.g., formed
by grinding methods only). Examples of non-precipitated particles
may include, but are not limited to, particles having a specific
gravity greater than about 2.6 comprising at least one of
BaSO.sub.4, CaCO.sub.3, (Ca,Mg)CO.sub.3, FeCO.sub.3,
Fe.sub.2O.sub.3, .alpha.-Fe.sub.2O.sub.3, .alpha.-FeO(OH),
Fe.sub.3O.sub.3, FeTiO.sub.3, (Fe,Mg)SiO.sub.4, SrSO.sub.4, MnO,
MnO.sub.2, Mn.sub.2O.sub.3, Mn.sub.3O.sub.3, Mn.sub.2O.sub.7,
MnO(OH), (Mn.sup.2+,Mn.sup.3+).sub.2O.sub.4, barite, calcium
carbonate, dolomite, hematite, siderite, magnetite, manganese
dioxide, manganese (IV) oxide, manganese oxide, manganese
tetraoxide, manganese (II) oxide, manganese (III) oxide, AgI, AgCl,
AgBr, AgCuS, AgS, Ag.sub.2S, Ag.sub.3SbS.sub.3, AgSbS.sub.2,
AgSbS.sub.2, AgsSbS.sub.4, (AgFe.sub.2S.sub.3), Ag.sub.3AsS.sub.3,
Ag.sub.3AsS.sub.3, Cu(Ag,Cu).sub.6Ag.sub.9As.sub.2S.sub.11,
[(Ag,Cu).sub.6(Sb,As).sub.2S.sub.7][Ag.sub.9CuS.sub.4],
Ag.sub.3AuTe.sub.2, (Ag,Au)Te.sub.2, Ag.sub.2Te, Al.sub.2O.sub.3,
Al.sub.2SiO.sub.5, AsSb, (Co,Ni,Fe)As.sub.3, PtAs.sub.2,
AuTe.sub.2, BaCO.sub.3, BaO, BeO, Bi, BiOCl, (BiO).sub.2CO.sub.3,
BiO.sub.3, Bi.sub.2S.sub.3, Bi.sub.2O.sub.3, CaO, CaF.sub.2,
CaWO.sub.4, CdS, CdTe, Ce.sub.2O.sub.3, CoAsS,
Co.sup.+2C.sup.+3.sub.2S.sub.4, (Fe,Mg)Cr.sub.2O.sub.4,
Cr.sub.2O.sub.3, Cu, CuO, Cu.sub.2O, CuS, Cu.sub.2S, CuS.sub.2,
Cu.sub.9S.sub.5, CuFeS.sub.2, Cu.sub.5FeS.sub.4,
CuS.Co.sub.2S.sub.3, Cu.sub.3AsO.sub.4(OH).sub.3,
Cu.sub.3AsS.sub.4, Cu.sub.12As.sub.4S.sub.13,
Cu.sub.2(AsO.sub.4)(OH), CuPb.sub.13Sb.sub.7S.sub.24,
CuSiO.sub.3.H.sub.2O, Fe.sub.3Al.sub.2(SiO.sub.4).sub.3,
Fe.sup.2+Al.sub.2O.sub.4, Fe.sub.2SiO.sub.4, FeWO.sub.4,
FeAs.sub.2, FeAsS, FeS, FeS.sub.2, Fe.sub.(1-x)S (wherein x=0 to
0.2), (Fe,Ni).sub.9S.sub.8, Fe.sup.2+Ni.sub.2.sup.3+S.sub.4,
(Fe,Mn)WO.sub.4, Fe.sup.2+ Nb.sub.2O.sub.6,
(Mn,Fe,Mg)(Al,Fe).sub.2O.sub.4,
CaFe.sup.2+.sub.2Fe.sup.3+Si.sub.2O.sub.7O(OH),
(YFe.sup.3+Fe.sup.2+U,Th,Ca).sub.2(Nb,Ta).sub.2O.sub.8, HgS,
Hg.sub.2Cl.sub.2, MgO, MnCO.sub.3, Mn.sub.2S, Mn.sub.2SiO.sub.4,
MnWO.sub.4, Mn(II).sub.3Al.sub.2(SiO.sub.4).sub.3,
(Na.sub.0.3Ca.sub.0.1K.sub.0.1)(Mn.sup.4+,Mn.sup.3+).sub.2O.sub.4.1.5
H.sub.2O, (Mn,Fe).sub.2O.sub.3,
(Mn.sup.2+,Fe.sup.2+,Mg)(Fe.sup.3+,Mn.sup.3+).sub.2O.sub.4,
(Mn.sup.2+,Mn.sup.3+).sub.6[O.sub.8|SiO.sub.4],
Ca(Mn.sup.3+,Fe.sup.3+).sub.14SiO.sub.24,
Ba(Mn.sup.2+)(Mn.sup.4+).sub.8O.sub.16(OH).sub.4, CaMoO.sub.4,
MoS.sub.2, MOO.sub.2, MOO.sub.3, NbO.sub.4,
(Na,Ca).sub.2Nb.sub.2O.sub.6(OH,F),
(Y,Ca,Ce,U,Th)(Nb,Ta,Ti).sub.2O.sub.6,
(Y,Ca,Ce,U,Th)(Ti,Nb,Ta).sub.2O.sub.6, (Fe,Mn)(Ta,Nb).sub.2O.sub.6,
(Ce,La)PO.sub.4, (Ce,La,Ca)BSiO.sub.5, (Ce,La)CO.sub.3F,
(Y,Ce)CO.sub.3F, (U,Ca,Y,Ce)(Ti,Fe).sub.2, NiO, NiAs.sub.2, NiAs,
NiAsS, Ni.sub.xFe(x=2-3), (Ni, Co).sub.3S.sub.4, NiS, PbTe,
PbSO.sub.4, PbCrO.sub.4, PbWO.sub.4, PbSiO.sub.3, PbCO.sub.3,
(PbCl).sub.2CO.sub.3, Pb.sub.5(PO.sub.4).sub.3Cl,
Pb.sub.5(AsO.sub.4).sub.3Cl, Pb.sup.2+.sub.2Pb.sup.4+O.sub.4,
Pb.sub.5Au(Te,Sb).sub.4S.sub.5-8, Pb.sub.5Sb.sub.8S.sub.17, PbS,
Pb.sub.9Sb.sub.8S.sub.21, Pb.sub.14(Sb,As).sub.6S.sub.23,
Pb.sub.5Sb.sub.4S.sub.11, Pb.sub.4FeSb.sub.6S.sub.14,
PbCu[(OH).sub.2|SO.sub.4], PbCuSbS.sub.3,
(Cu,Fe).sub.12Sb.sub.4S.sub.13, Sb.sub.2S.sub.3,
(Sb.sup.3+,Sb.sup.5+)O.sub.4, Sb.sub.2SnOs.sub.5, Sc.sub.2O.sub.3,
SnO, SnO.sub.2, Cu.sub.2FeSnS.sub.4, SrO, SrCO.sub.3, (Na,
Ca).sub.2Ta.sub.2O.sub.6(O,OH,F), ThO.sub.2, (Th,U)SiO.sub.4,
TiO.sub.2, UO.sub.2, V.sub.2O.sub.3, VO.sub.2, V.sub.2O.sub.5,
Pb.sub.5(VO.sub.4).sub.3Cl, VaO, Y.sub.2O.sub.3, YPO.sub.4,
ZnCO.sub.3, ZnO, ZnFe.sub.2O.sub.4, ZnAl.sub.2O.sub.4, ZnCO.sub.3,
ZnS, ZnO, (Zn.sub.(1-x)Fe.sub.(x)S), (Zn,Fe)S, ZrSiO.sub.4,
ZrO.sub.2, ZrSiO.sub.4, acanthite, alamandite, allemontite,
altaite, aluminum oxide, andalusite, anglesite, antimony sulfide,
antimony tin oxide, antimony trioxide, argentite, arsenopyrite,
awaruite, barium carbonate, barium oxide, bastnaesite, beryllium
oxide, birnessite, bismite, bismuth, bismuth oxycarbonates, bismuth
oxychloride, bismuth sulfide, bismuth sulfide, bismuth trioxide,
bismuth (III) oxide, bixbyite, bornite, boulangerite, bournonite,
brannerite, braunite, bravoite, bromyrite, cadimum sulfide, cadimum
telluride, calayerite, calcium oxide, calomel, carrollite,
cassiterite, celestine, cerargyrite, cerium oxide, cerussite,
cervantite, chalcocite, chalcopyrite, chromite, chromium oxide,
cinnabar, clinoclase, cobaltite, columbite, copper, copper oxide,
copper sulfide, corundum, covellite, crocoite, cuprite, danaite,
digenite, embolite, enargite, euxenite, fayalite, ferberite,
fergusonite, ferrous sulfide, franklinite, gahnite, galaxite,
galena, geocronite, geothite, gersdorffite, greenockite,
hausmmanite, hercynite, hessite, huebnerite, ilmenite, ilvaite,
iodyrite, iridosmine, Jacobsite, Jamesonite, krennerite, larsenite,
linarite, linnaeite, loellingite, magnesium oxide, manganese
carbonate, manganite, manganosite, marcasite, marmatite,
menaghinite, miargyrite, microlite, millerite, mimetite, minium,
molybdenite, molybdenum (IV) oxide, molybdenum oxide, molybdenum
trioxide, monazite, nagyagite, niccolite, nickel oxide, pearceite,
pentlandite, perovskite, petzite, phosgenite, phyromorphite,
plagionite, polianite, polybasite, polycrase, powellite, proustite,
psilomelane, pyrargyrite, pyrite, pyrochlore, pyrolusite,
pyrrhotite, rammelsbergite, rutile, samarskite, scandium oxide,
scheelite, semsyite, siegenite, skutterudite, smithsonite,
spalerite, sperrylite, spessartite, sphalerite, stannite,
stephanite, sternbergite, stibnite, stillwellite, stolzite,
Stromeyerite, strontium oxide, sylvanite, tantalite, tennantite,
tenorite, tephroite, tetrahedrite, thorianite, thorite, tin
dioxide, tin (II) oxide, titanium dioxide, turgite, uraninite,
vanadinite, vanadium oxide, vanadium trioxide, vanadium (IV) oxide,
vanadium (V) oxide, violarite, witherite, wolframite, wulfenite,
wurtzite, xenotime, yttrium oxide, zinc carbonate, zincite,
zinkenite, zircon, zirconium oxide, zirconium silicate, zinc oxide,
and suitable combinations thereof.
[0053] The precipitated particles (optionally in combination with
non-precipitated particle) may be present in the wellbore fluid in
an amount sufficient for a particular application. In certain
embodiments, the precipitated particles may be present in a
wellbore fluid in an amount up to about 70% by volume of the
wellbore fluid (v %) (e.g., about 5 v %, about 15 v %, about 20 v
%, about 25 v %, about 30 v %, about 35 v %, about 40 v %, about 45
v %, about 50 v %, about 55 v %, about 60 v %, about 65 v %, etc.).
In certain embodiments, the precipitated particles may be present
in the wellbore fluid in an amount of 10 v % to about 40 v %.
[0054] As described above, the precipitated particles described
herein may have tailored characteristics that can be exploited to
achieve desired properties and/or capabilities in a wellbore fluid
beyond density, e.g., sag control. Particles (e.g., weighting
agents, proppants, and cement particles) in wellbore fluids can
settle from or migrating within the wellbore fluid therein, which
is a condition known as "sag." As used herein, the term "sag"
refers to an inhomogeneity in density of a fluid in a wellbore,
e.g., along the length of a wellbore and/or the diameter of a
deviated wellbores. In some instances, sag can cause to portions of
the wellbore fluid to be at an insufficient density to stabilize
the wellbore and other portions of the wellbore fluid to have
increased density. Unstabilized portions of the wellbore can lead
to wellbore collapse and/or pressure buildups that cause blowouts.
Increased density can cause wellbore damage (e.g., undesired
fracturing of the wellbore), which may show up as pressure
increases or decreases when changing from static to flow conditions
of the fluid which can cause higher than desired pressures
downhole.
[0055] In some embodiments, the precipitated particles described
herein may be sized, shaped, or otherwise treated (e.g., coated) so
as to mitigate sag in wellbore fluids. The size may, inter alia,
provide for the formation of a stable suspension that exhibit low
viscosity under shear. Further, the specific gravity of the
precipitated particles may further allow for such precipitated
particles to provide for a desired density of the wellbore fluid
while mitigating sag of these precipitated particles or other
particles therein.
[0056] Sag control can be measured by analyzing density changes in
an undisturbed sample of wellbore fluid over time at a typical
wellbore temperature (e.g., about 300.degree. F.) and an elevated
pressure (e.g., about 5,000 psi to about 10,000 psi). For example,
the precipitated particles described herein that provide effective
sag control may, in some embodiments, yield wellbore fluids having
a change in density of less than about 1 ppg (e.g., about 0.5 ppg
change or less including no change in density) when comparing a
fluid's original density to the fluid's density at the bottom of a
sample having been undisturbed for a given amount of time. In some
embodiments, the precipitated particles described herein may
provide sag control (i.e., a density change of less than about 1
ppg) over a time ranging from a lower limit of about 10 hours, 24
hours, 36 hours, or 48 hours to an upper limit of about 120 hours,
96 hours, 72 hours, or 48 hours, and wherein the sag control
timeframe of the wellbore fluid may range from any lower limit to
any upper limit and encompasses any subset therebetween.
[0057] In some embodiments, the properties of the precipitated
particles described herein may be tailored to achieve sag control.
Properties of the precipitated particles that can be tailored to
achieve sag control may include, but are not limited to, size
(e.g., median diameter of about 2 microns or less or at least one
mode of a multimodal distribution having such a peak diameter),
shape (e.g., particle shapes with lower sphericity like discus,
platelet, flake, acicular, spiked with a substantially spherical or
ovular shape, spiked with a discus or platelet shape, fibrous,
toroidal, and the like), coatings, linking (described further
herein), and the like, and any combination thereof.
[0058] In some embodiments, when using two or more precipitated
particles with different specific gravities to produce a
homogeneous wellbore fluid, the size and shape of each of the
precipitated particles may be tailored so as to minimize separation
of the precipitated particles, which may lead to a wellbore fluid
with a striated density profile. For example, a first precipitated
particle with a discus or platelet shape may impede the settling of
a second precipitated particle that has a high settling or
migration rate (e.g., a higher specific gravity, spherical
particle).
[0059] In some embodiments, the properties of the precipitated
particles described herein may be tailored to mitigate the abrasion
of wellbore tools (e.g., pumps, drill bits, drill string, and a
casing) as compared to comparable API grade barite (i.e., a
comparable wellbore fluid having the same density and/or sag as the
wellbore fluid comprising the precipitated particles), which may
prolong the life of the wellbore tools. It should be noted that the
term "wellbore tools" encompasses tools suitable for use in
conjunction with wellbore operations, including tools that are used
outside of the wellbore, e.g., pumps, shakers, and the like.
Abrasion can be measured by the ASTM G75-07 and is reported as a
Miller Number or a SAR Number.
[0060] Suitable precipitated particles can be those with properties
tailored to mitigate abrasion, which may include, but are not
limited to, hardness (e.g., a Mohs hardness of less than about 5),
size (e.g., median diameter less than about 400 nm or mode of a
multimodal distribution having an peak diameter less than about 400
nm), shape (e.g., particle shapes with higher sphericity like
spherical, substantially spherical, ovular, substantially ovular,
and the like), coatings (e.g., thicker and/or elastic coatings that
minimize physical interactions between the mineral portion of the
precipitated particle and the wellbore tool), and the like, and any
combination thereof. For example, the wellbore fluids may comprise
substantially spherical awaruite particles with a median diameter
less than about 400 nm and manganese carbonate particles, which
have a Mohs hardness less than about 5.
[0061] At least some of the precipitated particles described herein
may, in some embodiments, be capable of being linked by linking
agents. Linking of precipitated particles may allow for increasing
the viscosity of the wellbore fluid or forming a solid mass
described further herein. One skilled in the art with the benefit
of this disclosure should recognize that, inter alia, the
composition of the precipitated particles described herein may
determine if the precipitated particles are suitable for being
linked and to what degree they can be linked. Examples of linkable
precipitated particles may include, but are not limited to, those
that comprise at least one of Al.sub.2O.sub.3, BaCO.sub.3, BaO,
BeO, (BiO).sub.2CO.sub.3, BiO.sub.3, Bi.sub.2O.sub.3, CaO,
CaCO.sub.3, (Ca,Mg)CO.sub.3, CdS, CdTe, Ce.sub.2O.sub.3,
Cr.sub.2O.sub.3, CuO, Cu.sub.2O, Fe.sup.2+Al.sub.2O.sub.4,
Fe.sub.2SiO.sub.4, FeCO.sub.3, Fe.sub.2O.sub.3,
.alpha.-Fe.sub.2O.sub.3, .alpha.-FeO(OH), Fe.sub.3O.sub.3,
FeTiO.sub.3, MgO, MnCO.sub.3, MnO, MnO.sub.2, Mn.sub.2O.sub.3,
Mn.sub.3O.sub.3, Mn.sub.2O.sub.7, MnO(OH), CaMoO.sub.4, MoS.sub.2,
MOO.sub.2, MOO.sub.3, NbO.sub.4, NiO, NiAs.sub.2, NiAs, NiAsS, NiS,
PbCO.sub.3, (PbCl).sub.2CO.sub.3, Sb.sub.2SnO.sub.5,
Sc.sub.2O.sub.3, SnO, SnO.sub.2, SrO, SrCO.sub.3, SrSO.sub.4,
TiO.sub.2, UO.sub.2, V.sub.2O.sub.3, VO.sub.2, V.sub.2O.sub.5, VaO,
Y.sub.2O.sub.3, YPO.sub.4, ZnCO.sub.3, ZnO, ZnFe.sub.2O.sub.4,
ZnAl.sub.2O.sub.4, ZrSiO.sub.4, ZrO.sub.2, ZrSiO.sub.4, and any
combination thereof. Additionally, in precipitated particles with
discrete domains, precipitated particles having any of the
foregoing in a domain accessible to be linked may also be
suitable.
[0062] Examples of linking agents suitable for use in conjunction
with the precipitated particles may, in some embodiments, include,
but are not limited to, eugenol, guaiacol, methyl guaiacol,
salicyladehyde, salicyladimine, salicylic acid, sodium salicylate,
acetyl salicylic acid, methyl salicylic acid, methyl
acetylsalicylic acid, anthranilic acid, acetyl anthranilic acid,
vanillin, derivatized 1,2-dihydroxybenzene (catechol), derivatized
or unsubstituted phthalic acid, ortho-phenylenediamine,
ortho-aminophenol, ortho-hydroxyphenylacetic acid, alkylsilanes,
esters, ethers, and the like, and any combination thereof.
Additionally polymers of the foregoing examples, or suitable
derivatives thereof, may used as linking agents. For example, vinyl
derivatives of the foregoing examples may be used in synthesizing a
polymer or copolymer suitable for use as a linking agents. In
another example, carboxylated derivates of the foregoing examples
may be used in derivatizing a polyamine to yield suitable linking
agents. Additional examples may include, but are not limited to,
compounds (including polymers and lower molecular weight molecules)
having at least two silane moieties, ester moieties, ether
moieties, sulfide moieties, amine moieties, and the like, and any
combination thereof.
[0063] Viscosity increases from linking with linking agents may, in
some embodiments, yield wellbore fluids that remain pumpable,
wellbore fluids that are non-pumpable, or hardened masses. One
skilled in the art with the benefit of this disclosure should
understand that the extent of the viscosity increase may depend on,
inter alia, the composition of the precipitated particles described
herein, the composition of the linking agents, the relative
concentration of the precipitated particles and the linking agents,
intended use, additional components in the wellbore fluid, and any
combination thereof.
[0064] In some embodiments, the precipitated particles described
herein may advantageously have a higher unconfined compressive
strength (e.g., about 1200 psi or greater) that allow for
load-bearing applications (e.g., proppant applications). In some
embodiments, the precipitated particles described herein may
advantageously have a moderate to high unconfined compressive
strength (e.g., about 500 psi or greater) that allow for
implementation in applications like cements, wellbore strengthening
additives, and gravel packs. The unconfined compressive strength of
a precipitated particle may depend on, inter alia, the composition
of the precipitated particle, the shape of the precipitated
particle, additional processing steps in producing the precipitated
particle (e.g., calcining after precipitation), and the like, and
any combination thereof.
[0065] While a plurality of the precipitated particles described
herein may have high compressive strength, in some preferred
embodiments, such precipitated particles may comprise at least one
of Al.sub.2O.sub.3, CaF.sub.2, CaWO.sub.4, CaCO.sub.3,
(Ca,Mg)CO.sub.3, CuO, Cu.sub.2O, CuS, Cu.sub.2S, CuS.sub.2,
Cu.sub.9S.sub.5, CuFeS.sub.2, Cu.sub.5FeS.sub.4,
CuS.Co.sub.2S.sub.3, Fe.sup.2+Al.sub.2O.sub.4, Fe.sub.2SiO.sub.4,
FeWO.sub.4, FeS, FeS.sub.2, FeCO.sub.3, Fe.sub.2O.sub.3,
.alpha.-Fe.sub.2O.sub.3, .alpha.-FeO(OH), Fe.sub.3O.sub.3,
FeTiO.sub.3, MnCO.sub.3, Mn.sub.2S, MnWO.sub.4, MnO, MnO.sub.2,
Mn.sub.2O.sub.3, Mn.sub.3O.sub.3, Mn.sub.2O.sub.7, MnO(OH),
CaMoO.sub.4, MOO.sub.2, MoO.sub.3, NiO, NiS, SnO, SnO.sub.2,
TiO.sub.2, ZnCO.sub.3, ZnO, ZnFe.sub.2O.sub.4, ZnAl.sub.2O.sub.4,
ZnS, ZrSiO.sub.4, ZrO.sub.2, ZrSiO.sub.4, and any combination
thereof.
[0066] At least some of the precipitated particles described herein
may, in some embodiments, be at least partially degradable. As used
herein, the term "degradable" refers to a material being capable of
reduced in size by heterogeneous degradation (or bulk erosion) and
homogeneous degradation (or surface erosion), and any stage of
degradation in between these two. This degradation can be a result
of, inter alia, a chemical or thermal reaction, for example,
dissolution by an acidic fluid. One skilled in the art with the
benefit of this disclosure should recognize that, inter alia, the
composition of the precipitated particles described herein may
determine if the precipitated particles are degradable and to what
extent they are degradable.
[0067] While a plurality of the precipitated particles described
herein may have be degradable, in some preferred embodiments,
degradable precipitated particles may comprise at least one of
BaCO.sub.3, (BiO).sub.2CO.sub.3, CaWO.sub.4, CaCO.sub.3, CuO,
FeCO.sub.3, PbCO.sub.3, (PbCl).sub.2CO.sub.3, SrCO.sub.3,
ZnCO.sub.3, and any combination thereof.
[0068] Degradation of the precipitated described herein may
advantageously be used in a plurality of wellbore operations, e.g.,
cleanup operations (e.g., in removing a filter cake or plug from a
lost circulation operation) and cementing operations (e.g., in
enhancing the permeability of a cement plug to allow for fluid to
flow therethrough while still providing structural strength).
Additionally, degradation may be advantageous in reducing the
viscosity of a fluid by degrading precipitated particles that
contribute to the viscosity (e.g., by shape and/or by linking).
[0069] Examples of degradation agents that may be useful in at
least partially degrading precipitated particles described herein
may, in some embodiments, include, but are not limited to, acid
sources (e.g., inorganic acids, organic acid, and polymers that
degrade into acids like polylactic acid), alkaline sources (e.g.,
bases), and oxidizers (e.g., peroxide compounds, permanganate
compounds, and hexavalent chromium compounds).
[0070] In some embodiments, the precipitated particles described
herein may be chosen so as to degrade over a desired amount of
time, which may be dependent on, inter alia, particle size,
particle shape, wellbore temperature, and precipitated particle
composition. For example, calcium carbonate rather than lead
carbonate may be utilized, in some embodiments, when for faster
degradation. In another example, manganese carbonate may, in some
embodiments, be chosen for slower degradation in colder wellbore
environments and faster degradation in hotter wellbore
environments.
[0071] In some embodiments, the precipitated particles described
herein may have a coating on at least a portion of the surface of
the precipitated particles. As used herein, the term "coating," and
the like, does not imply any particular degree of coating on the
particle. In particular, the terms "coat" or "coating" do not imply
100% coverage by the coating on the particle. Further, a coating
may, in some embodiments, be covalently and/or noncovalently
associate with the precipitated particles described herein.
[0072] In some embodiments, a coating suitable for use in
conjunction with the precipitated particles described herein may
include, but are not limited to, polymers, surfactants, and any
combination thereof. Coatings may, in some embodiments, assist in
the suspension of the precipitated particles and/or the
compatibility of the precipitated particles with a wellbore fluid
and/or wellbore operation. For example, a coating like an alkyl
amine may, in some embodiments, associate with the surface of the
precipitated particles so as to render the precipitated particle
more hydrophobic, which may enhance the suspendability of the
precipitated particles in oil-based fluids.
[0073] In some embodiments, precipitated particles may be coated
after addition to the wellbore fluid.
[0074] In some embodiments, a coating may be applied during
production of the precipitated particles described herein. For
example, grinding production methods may, in some embodiments, be
conducted in the presence of polymers, surfactants, or the like
suitable for use as a coating. Additionally, in some embodiments,
precipitation production methods may be conducted in the presence
of polymers, surfactants, or the like suitable for use as a
coating. One skilled in the art with the benefit of this disclosure
should understand that including polymers, surfactants, or the like
in a production method of the precipitated particles described
herein should be chosen so as not to significantly impact the
production in a negative manner.
[0075] Polymers suitable for use in conjunction with the coated
precipitated particles described herein may, in some embodiments,
have a molecular weight ranging from a lower limit of about 10,000
g/mol, 25,000 g/mol, 100,000 g/mol, or 250,000 g/mol to an upper
limit of about 2,000,000 g/mol, 1,000,000 g/mol, 500,000 g/mol, or
250,000 g/mol, and wherein the molecular weight may range from any
lower limit to any upper limit and encompasses any subset
therebetween.
[0076] In some embodiments, coating may comprise the polymers list
herein that may be useful as morphology modifiers. In some
embodiments, the polymers may be used as morphology modifiers any
yield coated precipitated particles. In other instances, the
precipitated particles may be formed and then polymers suitable for
use as morphology modifiers may be used as coatings.
[0077] In some embodiments, coatings may comprise consolidating
agents that generally comprise any compound that is capable of
minimizing particulate migration once placed, which may be suitable
for methods and compositions relating to proppant packs, gravel
packs, and the like. Suitable consolidating agents may include, but
are not limited to, non-aqueous tackifying agents, aqueous
tackifying agents, emulsified tackifying agents, silyl-modified
polyamide compounds, resins, crosslinkable aqueous polymer
compositions, polymerizable organic monomer compositions,
consolidating agent emulsions, zeta-potential modifying aggregating
compositions, silicon-based resins, and binders. Combinations
and/or derivatives of these also may be suitable. Nonlimiting
examples of suitable non-aqueous tackifying agents may be found in
U.S. Pat. Nos. 7,392,847, 7,350,579, 5,853,048; 5,839,510; and
5,833,000, the entire disclosures of which are herein incorporated
by reference. Nonlimiting examples of suitable aqueous tackifying
agents may be found in U.S. Pat. Nos. 8,076,271, 7,131,491,
5,249,627 and 4,670,501, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable
crosslinkable aqueous polymer compositions may be found in U.S.
Patent Application Publication No. 2010/0160187 and U.S. Pat. No.
8,136,595 the entire disclosures of which are herein incorporated
by reference. Nonlimiting examples of suitable silyl-modified
polyamide compounds may be found in U.S. Pat. No. 6,439,309
entitled the entire disclosure of which is herein incorporated by
reference. Nonlimiting examples of suitable resins may be found in
U.S. Pat. Nos. 7,673,686; 7,153,575; 6,677,426; 6,582,819;
6,311,773; and 4,585,064 as well as U.S. Patent Application
Publication No. 2008/0006405 and U.S. Pat. No. 8,261,833, the
entire disclosures of which are herein incorporated by reference.
Nonlimiting examples of suitable polymerizable organic monomer
compositions may be found in U.S. Pat. No. 7,819,192, the entire
disclosure of which is herein incorporated by reference.
Nonlimiting examples of suitable consolidating agent emulsions may
be found in U.S. Patent Application Publication No. 2007/0289781
the entire disclosure of which is herein incorporated by reference.
Nonlimiting examples of suitable zeta-potential modifying
aggregating compositions may be found in U.S. Pat. Nos. 7,956,017
and 7,392,847, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable
silicon-based resins may be found in Application Publication Nos.
2011/0098394, 2010/0179281, and U.S. Pat. Nos. 8,168,739 and
8,261,833, the entire disclosures of which are herein incorporated
by reference. Nonlimiting examples of suitable binders may be found
in U.S. Pat. Nos. 8,003,579; 7,825,074; and 6,287,639, as well as
U.S. Patent Application Publication No. 2011/0039737, the entire
disclosures of which are herein incorporated by reference. It is
within the ability of one skilled in the art, with the benefit of
this disclosure, to determine the type and amount of consolidating
agent to include in the methods of the present invention to achieve
the desired results.
[0078] In some embodiments, the wellbore additives may comprise the
precipitated particles described herein and optionally further
comprise other particles and/or additional components suitable for
use in a specific wellbore operation (e.g., proppants and cement
particles as described further herein). Wellbore additives may, in
some embodiments, be dry powder or gravel, a liquid with a high
concentration of the precipitated particles described herein (e.g.,
a slurry), and the like.
[0079] As described herein, in some embodiments, it may be
advantageous to include a combination of types of precipitated
particles described herein so as to achieve a wellbore fluid with
desired properties and/or capabilities. The ratio of the various
particles may depend on, inter alia, the desired properties and/or
characteristics of the wellbore fluid.
[0080] Distinctions between types of precipitated particles may, in
some embodiments, be defined by at least one of mineral
composition, production method, median diameter, diameter
distribution, presence or absence of coating, coating composition,
and the like, and any combination thereof. As such, achieving
homogeneous mixtures of dry wellbore additives may be aided by
inclusion of a dry lubricant to facilitate homogeneous mixing and
flowability. Examples of dry lubricant may, in some embodiments,
include, but are not limited to, molybdenum disulfide, graphite,
boron nitride, tungsten disulfide, polytetrafluoroethylene
particles, bismuth sulfide, bismuth oxychloride, and the like, and
any combination thereof. In some embodiments, a dry lubricant may
advantageously have a specific gravity greater than about 2.6
(e.g., molybdenum disulfide, tungsten disulfide, bismuth sulfide,
and bismuth oxychloride) so as contribute to the density of the
resultant wellbore fluid.
[0081] Examples of base fluids suitable for use in conjunction with
the wellbore fluids may, in some embodiments, include, but are not
limited to, 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, and potassium carbonate; any in
combination with an aqueous-based fluid; and any combination
thereof.
[0082] 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 30:70, 40:60, 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
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
entitled "Invert Emulsion Fluids Suitable for Drilling" filed on
May 23, 1997, U.S. Pat. No. 5,977,031 entitled "Ester Based Invert
Emulsion Drilling Fluids and Muds Having Negative Alkalinity" filed
on Aug. 8, 1998, U.S. Pat. No. 6,828,279 entitled "Biodegradable
Surfactant for Invert Emulsion Drilling Fluid" filed on Aug. 10,
2001, U.S. Pat. No. 7,534,745 entitled "Gelled Invert Emulsion
Compositions Comprising Polyvalent Metal Salts of an
Organophosphonic Acid Ester or an Organophosphinic Acid and Methods
of Use and Manufacture" filed on May 5, 2004, U.S. Pat. No.
7,645,723 entitled "Method of Drilling Using Invert Emulsion
Drilling Fluids" filed on Aug. 15, 2007, and U.S. Pat. No.
7,696,131 entitled "Diesel Oil-Based Invert Emulsion Drilling
Fluids and Methods of Drilling Boreholes" filed on Jul. 5, 2007,
each of which are incorporated herein by reference in their
entirety. 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
being and/or comprising an aqueous-miscible fluid.
[0083] In some embodiments, the wellbore fluids described herein
may be foamed. As used herein, the term "foam" refers to a
two-phase composition having a continuous liquid phase and a
discontinuous gas phase. In some embodiments, the wellbore fluids
may comprise a base fluid, the precipitated particles described
herein, a gas, and a foaming agent.
[0084] Examples of gases may include, but are not limited to,
nitrogen, carbon dioxide, air, methane, helium, argon, and any
combination thereof. One skilled in the art, with the benefit of
this disclosure, should understand the benefit of each gas. By way
of nonlimiting example, carbon dioxide foams may have deeper well
capability than nitrogen foams because carbon dioxide emulsions
have greater density than nitrogen gas foams so that the surface
pumping pressure required to reach a corresponding depth is lower
with carbon dioxide than with nitrogen. Moreover, the higher
density may impart greater particle transport capability, up to
about 12 lb of particles per gal of wellbore fluid.
[0085] In some embodiments, the quality of a wellbore fluid that is
foamed may range from a lower limit of about 5%, 10%, 25%, 40%,
50%, 60%, or 70% gas volume to an upper limit of about 95%, 90%,
80%, 75%, 60%, or 50% gas volume, and wherein the quality may range
from any lower limit to any upper limit and encompasses any subset
therebetween. Most preferably, the wellbore fluid that is foamed
may have a foam quality from about 85% to about 95%, or about 90%
to about 95%.
[0086] Examples of foaming agents may include, but are not limited
to, cationic foaming agents, anionic foaming agents, amphoteric
foaming agents, nonionic foaming agents, or any combination
thereof. Nonlimiting examples of suitable foaming agents may, in
some embodiments, include, but are not limited to, surfactants like
betaines, sulfated or sulfonated alkoxylates, alkyl quarternary
amines, alkoxylated linear alcohols, alkyl sulfonates, alkyl aryl
sulfonates, C.sub.10-C.sub.20 alkyldiphenyl ether sulfonates,
polyethylene glycols, ethers of alkylated phenol, sodium
dodecylsulfate, alpha olefin sulfonates such as sodium dodecane
sulfonate, trimethyl hexadecyl ammonium bromide, and the like, any
derivative thereof, or any combination thereof. Foaming agents may
be included in foamed treatment fluids at concentrations ranging
typically from about 0.05% to about 2% of the liquid component by
weight (e.g., from about 0.5 to about 20 gallons per 1000 gallons
of liquid).
[0087] In some embodiments, the wellbore additives and/or the
wellbore fluids described herein may optionally further comprise
additional components, e.g., filler particles, salts, inert solids,
fluid loss control agents, emulsifiers, dispersion aids, corrosion
inhibitors, emulsion thinners, emulsion thickeners, viscosifying
agents, gelling agents, crosslinking agents, surfactants, cement
particulates, proppants, gravel particulates, lost circulation
materials, pH control additives, breakers, defoaming agents,
biocides, stabilizers, scale inhibitors, gas hydrate inhibitors,
oxidizers, reducers, friction reducers, clay stabilizing agents,
set accelerators, set retarders, and combinations thereof. One
skilled in the art with the benefit of this disclosure should
understand the appropriate composition, concentration, and
combination of individual additional components that may be
included in the wellbore additives and/or the wellbore fluids that
comprise the precipitated particles described herein.
[0088] The wellbore additives and/or the wellbore fluids described
herein may be used in a plurality of wellbore operations. Examples
of wellbore operations may, in some embodiments, include, but are
not limited to, drilling operations, managed-pressure drilling
operations, dual-gradient drilling, tripping operations, logging
operations, lost circulation operations, stimulation operations,
sand control operations, completion operations, acidizing
operations, scale inhibiting operations, water-blocking operations,
clay stabilizer operations, fracturing operations, gravel packing
operations, wellbore strengthening operations, and sag control
operations. The wellbore additives and/or the wellbore fluids
described herein may, in some embodiments, be used in full-scale
operations or pills. As used herein, a "pill" is a type of
relatively small volume of specially prepared wellbore fluid placed
or circulated in the wellbore.
[0089] Some embodiments may involve circulating a wellbore fluid
that comprises a base fluid and precipitated particles described
herein in a wellbore such that the wellbore fluid has a desired
density and optionally a desired level of sag control. In some
instances, the wellbore fluid may be a drilling fluid, a wellbore
strengthening fluid, a cementing fluid, a fracturing fluid, a
plugging fluid, completion fluids, and the like and used in
corresponding wellbore operations. In some instances, the wellbore
fluid may further comprise other particles like a non-precipitated
weighting agent particles, proppant particles, cement particles,
lost circulation particles, and the like, and any combination
thereof. In some instances, the precipitated particles may be a
single type or multiple types of precipitated particles.
[0090] In some embodiments, the precipitated particles described
herein may be useful in drilling operations. Some embodiments may
involve drilling a wellbore penetrating a subterranean formation
with a wellbore fluid that comprises precipitated particles
described herein. In some embodiments, the precipitated particles
described herein may be useful in at least one of: suspending
wellbore cuttings (e.g., by contributing to the fluid viscosity
and/or sag control), maintaining wellbore pressure (e.g., by
contributing to sag control), incorporating into filter cakes that
provide fluid loss control, and the like. Further, precipitated
particles described herein may be chosen to mitigate abrasion of
wellbore tools utilized during drilling.
[0091] In some embodiments, the precipitated particles described
herein may be useful in drilling operations. Some embodiments may
involve drilling a wellbore penetrating a subterranean formation
with a wellbore fluid that comprises precipitated particles
described herein. In some embodiments, the precipitated particles
described herein may be useful in at least one of: suspending
wellbore cuttings (e.g., by contributing to the fluid viscosity
and/or sag control), maintaining wellbore pressure (e.g., by
contributing to sag control), incorporating into filter cakes that
provide fluid loss control, and the like. Further, precipitated
particles described herein may be chosen to mitigate abrasion of
wellbore tools utilized during drilling.
[0092] In some embodiments, the precipitated particles described
herein may be used in cementing operations. As used herein, the
term "cementing operations" refers to operations where a
composition is placed in a wellbore and/or a subterranean formation
and sets therein to form a hardened mass, which encompasses
hydraulic cements, construction cements, linked precipitated
particles described herein, and some polymeric compositions that
set (e.g., polymers like epoxies and latexes).
[0093] Examples of cementing operations that may utilize the
precipitated particles described herein may, in some embodiments,
include, but are not limited to, primary cementing operations
(e.g., forming cement sheaths in a wellbore annulus or forming
wellbore plugs for zonal isolation or fluid diversion) and remedial
cementing operations (e.g., squeeze operations, repairing and/or
sealing microannuli and/or cracks in a hardened mass, or forming
plugs). In cementing operations, a plurality of fluids are often
utilized including, but not limited to, cementing fluids (sometimes
referred to as settable compositions), spacer fluids, and
displacement fluids. For example, a cementing operation may
utilize, in order, (1) a first spacer fluid, (2) a cementing fluid,
optionally (3) a second spacer fluid, and (4) a displacement fluid,
each of which may independently be a wellbore fluid comprising
precipitated particles described herein.
[0094] In some embodiments, cementing operations may utilize a
plurality of fluids in order such that each subsequent fluid has a
higher density than the previous fluid. Achieving the desired
density for a wellbore fluid in a cementing operation may, in some
embodiments, involve the use of precipitated particles described
herein. Further, as described herein, the precipitated particles
utilized in such wellbore fluids may be chosen to achieve other
properties and/or capabilities in the wellbore fluids. It should be
noted that in a cementing operation when a plurality of wellbore
fluids are used, each wellbore fluid may be independently designed
with precipitated particles described herein and do not necessarily
require the use of the same precipitated particle in each of the
wellbore fluids or the use of a precipitated particle described
herein in all of the wellbore fluids. For example, the first spacer
fluid may include fluorite, the cementing fluid may include
precipitated manganese oxide, and the second spacer may include
precipitated copper oxide.
[0095] One of ordinary skill in the art should understand the
plurality of uses of the precipitated particles described herein
and the appropriate incorporation into the wellbore fluids suitable
for use in conjunction with cementing operations. For example,
cementing fluids, spacer fluids, and/or displacement fluids, may
comprise precipitated particles described herein so as to achieve a
desired density, a desired level of sag control, and/or a desired
viscosity. In another example, linkable precipitated particles may
be included in the cementing fluids and utilized so as to yield
hardened masses that comprise linked precipitated particles. In yet
another example, degradable precipitated particles may be included
in the cementing fluids and utilized so as to yield hardened masses
that that can be at least partially degraded. Further, depending on
the composition of the precipitated particle, combinations of the
foregoing examples may be appropriate, e.g., precipitated particles
comprising manganese carbonate may be useful in cementing fluids to
achieve a desired density and a desired level of sag control, to
link in forming the hardened mass, and to degrade for increasing
the permeability of the hardened mass.
[0096] The exemplary precipitated particles and related fluids
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 precipitated particles and related fluids. For example,
and with reference to FIG. 2, the disclosed precipitated particles
and related fluids may directly or indirectly affect one or more
components or pieces of equipment associated with an exemplary
wellbore drilling assembly 200, according to one or more
embodiments. It should be noted that while FIG. 2 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.
[0097] As illustrated, the drilling assembly 200 may include a
drilling platform 202 that supports a derrick 204 having a
traveling block 206 for raising and lowering a drill string 208.
The drill string 208 may include, but is not limited to, drill pipe
and coiled tubing, as generally known to those skilled in the art.
A kelly 210 supports the drill string 208 as it is lowered through
a rotary table 212. A drill bit 214 is attached to the distal end
of the drill string 208 and is driven either by a downhole motor
and/or via rotation of the drill string 208 from the well surface.
As the bit 214 rotates, it creates a wellbore 216 that penetrates
various subterranean formations 218.
[0098] A pump 220 (e.g., a mud pump) circulates drilling fluid 222
(e.g., a drilling fluid comprising the precipitated particles
described herein) through a feed pipe 224 and to the kelly 210,
which conveys the drilling fluid 222 downhole through the interior
of the drill string 208 and through one or more orifices in the
drill bit 214. The drilling fluid 222 is then circulated back to
the surface via an annulus 226 defined between the drill string 208
and the walls of the wellbore 216. At the surface, the recirculated
or spent drilling fluid 222 exits the annulus 226 and may be
conveyed to one or more fluid processing unit(s) 228 via an
interconnecting flow line 230. After passing through the fluid
processing unit(s) 228, a "cleaned" drilling fluid 222 is deposited
into a nearby retention pit 232 (i.e., a mud pit). While
illustrated as being arranged at the outlet of the wellbore 216 via
the annulus 226, those skilled in the art will readily appreciate
that the fluid processing unit(s) 228 may be arranged at any other
location in the drilling assembly 200 to facilitate its proper
function, without departing from the scope of the disclosure.
[0099] One or more of the disclosed precipitated particles may be
added to the drilling fluid 222 via a mixing hopper 234
communicably coupled to or otherwise in fluid communication with
the retention pit 232. The mixing hopper 234 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
precipitated particles may be added to the drilling fluid 222 at
any other location in the drilling assembly 200. In at least one
embodiment, for example, there could be more than one retention pit
232, such as multiple retention pits 232 in series. Moreover, the
retention put 232 may be representative of one or more fluid
storage facilities and/or units where the disclosed precipitated
particles may be stored, reconditioned, and/or regulated until
added to the drilling fluid 222.
[0100] As mentioned above, the disclosed precipitated particles and
related fluids may directly or indirectly affect the components and
equipment of the drilling assembly 200. For example, the disclosed
precipitated particles and related fluids may directly or
indirectly affect the fluid processing unit(s) 228 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) 228 may further include one or more sensors, gauges, pumps,
compressors, and the like used to store, monitor, regulate, and/or
recondition the exemplary precipitated particles and related
fluids.
[0101] The disclosed precipitated particles and related fluids may
directly or indirectly affect the pump 220, which representatively
includes any conduits, pipelines, trucks, tubulars, and/or pipes
used to fluidically convey the precipitated particles and related
fluids downhole, with pumps, compressors, or motors (e.g., topside
or downhole) used to drive the precipitated particles and related
fluids into motion, any valves or related joints used to regulate
the pressure or flow rate of the precipitated particles and related
fluids, and any sensors (i.e., pressure, temperature, flow rate,
etc.), gauges, and/or combinations thereof, and the like. The
disclosed precipitated particles and related fluids may also
directly or indirectly affect the mixing hopper 234 and the
retention pit 232 and their assorted variations.
[0102] The disclosed precipitated particles and related fluids may
also directly or indirectly affect the various downhole equipment
and tools that may come into contact with the precipitated
particles and related fluids such as, but not limited to, the drill
string 208, any floats, drill collars, mud motors, downhole motors
and/or pumps associated with the drill string 208, and any MWD/LWD
tools and related telemetry equipment, sensors or distributed
sensors associated with the drill string 208. The disclosed
precipitated particles and related fluids 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 216. The disclosed precipitated particles and
related fluids may also directly or indirectly affect the drill bit
214, which may include, but is not limited to, roller cone bits,
PDC bits, natural diamond bits, any hole openers, reamers, coring
bits, etc.
[0103] While not specifically illustrated herein, the disclosed
precipitated particles and related fluids may also directly or
indirectly affect any transport or delivery equipment used to
convey the precipitated particles and related fluids to the
drilling assembly 200 such as, for example, any transport vessels,
conduits, pipelines, trucks, tubulars, and/or pipes used to
fluidically move the precipitated particles and related fluids from
one location to another, any pumps, compressors, or motors used to
drive the precipitated particles and related fluids into motion,
any valves or related joints used to regulate the pressure or flow
rate of the precipitated particles and related fluids, and any
sensors (i.e., pressure and temperature), gauges, and/or
combinations thereof, and the like.
[0104] While not specifically illustrated herein, one of ordinary
skill in the art should recognize the modifications to drilling
assembly 200 to allow for performing other operations described
herein including, but not limited to, cementing operations,
fracturing operations, and fluid flow control operations.
[0105] In some embodiments, a wellbore drilling assembly may
comprise a pump in fluid communication with a wellbore via a feed
pipe; and a wellbore fluid described herein disposed in at least
one selected from the group consisting of the pump, the feed pipe,
the wellbore, and any combination thereof.
[0106] In some embodiments, a wellbore drilling assembly may
comprise a pump in fluid communication with a wellbore via a feed
pipe; a drill string with drill bit attached to the distal end of
the drill string; and a wellbore fluid described herein in contact
with the drill bit.
[0107] In some embodiments, a wellbore drilling assembly may
comprise a pump capable of introducing a fluid into a wellbore via
a feed pipe; a fluid processing unit capable of receiving the fluid
from a wellbore via an interconnecting flow line; and a wellbore
fluid described herein disposed in at least one selected from the
group consisting of the pump, the feed pipe, the wellbore, the
interconnecting flow line, the fluid processing unit, and any
combination thereof.
[0108] In some embodiments, a wellbore drilling assembly may
comprise a pump capable of introducing a fluid into a wellbore via
a feed pipe; a mixing hopper upstream of the pump; and a wellbore
fluid described herein disposed in at least one selected from the
group consisting of the pump, the feed pipe, the wellbore, and any
combination thereof. The mixing hopper may be useful, in some
embodiments, for implementing on-the-fly changes to the wellbore
fluids described herein.
[0109] In the foregoing wellbore drilling assembly embodiments
suitable wellbore fluids described herein may include, but are not
limited to,
[0110] (a) a wellbore fluid having a density of about 7 ppg to
about 50 ppg (including any subset described herein) and comprising
a base fluid and a plurality of precipitated particles having a
shape selected from the group consisting of ovular, substantially
ovular, discus, platelet, flake, toroidal, dendritic, acicular,
spiked with a substantially spherical or ovular shape, spiked with
a discus or platelet shape, rod-like, fibrous, polygonal, faceted,
star-shaped, and any hybrid thereof;
[0111] (b) the wellbore fluid of (a), wherein the wellbore fluid
has a sag control of a density change of less than about 1 ppg over
a time of about 10 hours to about 120 hours;
[0112] (c) the wellbore fluid of (a), wherein the precipitated
particles have a specific gravity of about 2.6 to about 20;
[0113] (d) the wellbore fluid of (a), wherein the precipitated
particles have a specific gravity of about 5.5 to about 20;
[0114] (e) the wellbore fluid of (a), wherein the precipitated
particles have a median diameter of about 5 nm to about 100
microns;
[0115] (f) the wellbore fluid of (a), wherein the wellbore fluid
further comprises a plurality of second particles, the second
particles being precipitated or non-precipitated;
[0116] (g) the wellbore fluid of (f), wherein the precipitated
particles in combination with the second particles have a
multiparticle specific gravity of about 3 to about 20;
[0117] (h) the wellbore fluid of (f), wherein the precipitated
particles in combination with the second particles have a diameter
distribution that has at least one mode with a standard deviation
of about 2% or less of a peak diameter of the mode; and
[0118] (i) the wellbore fluid of (f), wherein the precipitated
particles in combination with the second particles have a
multi-modal diameter distribution.
[0119] 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. 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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