BACKGROUND
This disclosure relates to methods of making and using a wellbore servicing fluid in a wellbore.
More specifically, it relates to methods of making and introducing a well bore servicing fluid into a wellbore
penetrating a subterranean formation.
[0002] Natural resources such as gas, oil, and water residing in a subterranean formation or zone are
usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid
in the wellbore. The drilling fluid is usually circulated downward through the interior of the drill pipe and
upward through the annulus, which is located between the exterior of the drill pipe and the interior wall of
the wellbore. Drilling may be halted and a string of casing is run into the wellbore, where residual drilling
fluid may fill a volume provided by the interior of the casing string and/or an annular space provided
between the exterior of the casing string and the interior wall of the wellbore. A spacer fluid is usually
placed in the wellbore to physically separate the residual drilling fluid from a cementitious fluid being
placed downhole after the spacer fluid. The cementitious fluid is placed into the wellbore downward
through the interior of the casing string and upward through the annulus wherein the cement is allowed to
set into a hard mass (i.e., sheath) to thereby attach the casing string to the walls of the wellbore and seal the
annulus. Prior to initiation of production, a completion fluid is introduced to the wellbore to facilitate final
operations such as setting screens, production liners, packers, downhole valves or shooting perforations into
the producing zone.
[0003] Also, in various scenarios, fluid in a wellbore may communicate with fluid in the subterranean
formation around the wellbore. It is well known that wellbores pass through a number of zones within a
subterranean formation other than the particular hydrocarbon zones of interest. Some of these zones are
permeable (i.e., permeable zones), and thus may have water influx, gas influx, or both from the subterranean
formation surrounding a wellbore into the wellbore. In one scenario, undesired water production, gas
production, or both can affect the economic life of hydrocarbon producing wells and can potentially induce
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other types of problems, such as sand production, scale, and corrosion of tubulars. In another scenario,
fluids used in servicing a wellbore may be lost to the subterranean formation while circulating the fluids in
the wellbore. In particular, the fluids may enter the subterranean formation via lost circulation zones, for
example, depleted zones, zones of relatively low pressure, zones having naturally occurring fractures, weak
zones having fracture gradients exceeded by the hydrostatic pressure of the wellbore servicing fluid (e.g.,
drilling fluid), and so forth. As a result, the service provided by such wellbore servicing fluids is more
difficult to achieve.
[0004] Accordingly, an ongoing need exists for compositions and methods of treating fluid loss in a
wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] For a more complete understanding of the present disclosure and the advantages thereof,
reference is now made to the following brief description, taken in connection with the accompanying
drawings and detailed description, wherein like reference numerals represent like parts.
[0006] FIGS. lA and lB are cross-sectional, side views of a wellbore penetrating a subterranean
formation, with a conduit disposed therein.
[0007] FIGS. 2A and 2B are cross-sectional, side views of a wellbore penetrating a subterranean
formation, with a conduit disposed therein.
DETAILED DESCRIPTION
[0008] It should be understood at the outset that although an illustrative implementation of one or more
embodiments are provided below, the disclosed systems and/or methods may be implemented using any
number of techniques, whether currently known or in existence. The disclosure should in no way be limited
to the illustrative implementations, drawings, and techniques illustrated below, including the exemplary
designs and implementations illustrated and described herein, but may be modified within the scope of the
appended claims along with their full scope of equivalents.
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[0009] As used herein, a "wellbore servicing fluid" refers to a fluid used to drill, complete, work over,
fracture, repair, or in any way prepare a wellbore for the recovery of materials residing in a subterranean
formation penetrated by the wellbore. Examples of well bore servicing fluids include, but are not limited to,
drilling fluids or muds, spacer fluids, lost circulation fluids, cement slurries, washing fluids, sweeping fluids,
acidizing fluids, fracturing fluids, gravel packing fluids, diverting fluids or completion fluids. It is to be
understood that "subterranean formation" encompasses both areas below exposed earth and areas below
earth covered by water such as ocean or fresh water.
[0010] Herein in the disclosure, "top" means the well at a well surface (e.g., at a wellhead which may
be located on dry land or below water, e.g., a subsea wellhead), and the direction along a wellbore towards
the well surface is referred to as "up"; "bottom" means the end of a wellbore away from the surface, and the
direction along a wellbore away from the wellbore surface is referred to as "down." For example, in a
horizontal wellbore, two locations may be at the same level (i.e., depth within a subterranean formation), the
location closer to the well surface (by comparing the lengths along the wellbore from the wellbore surface to
the locations) is referred to as "above" the other location.
[0011] A wellbore servicing fluid (WSF) is a fluid designed and prepared to resolve a specific wellbore
or reservoir condition. This disclosure involves a WSF that has fluid loss control properties. The WSF can
be used as a drilling fluid, a fluid loss control fluid (also referred to as a lost circulation fluid herein), a
spacer fluid, a cement fluid (also referred to as a cementitious fluid herein), or a completion fluid.
[0012] Disclosed herein is a method of servicing a wellbore penetrating a subterranean formation. The
method can comprise placing a wellbore servicing fluid (WSF) into the wellbore proximate a permeable
zone. As used herein, a permeable zone in the wellbore refers to an area in the wellbore or the subterranean
formation adjacent to the wellbore through which fluid can undesirably migrate. Such permeable zones may
be present in, for example, the subterranean formation surrounding a wellbore, the wall of a conduit
disposed in the wellbore such as a casing, a sealant/cement column disposed in an annulus ofthe wellbore
between the casing and a subterranean formation penetrated by the wellbore, a microannulus interposed
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between the casing and the sealant/cement column, a microannulus interposed between the sealant/cement
column and the formation, or combinations thereof. Permeable zones can include fluid flow paths
extending between the wellbore and the surrounding formation, for example, a fissure, a crack, a fracture, a
vug, a streak, a flow channel, a void, a perforation formed by a perforating gun, and combinations thereof.
In embodiments, the permeable zone is a loss circulation zone such as a fracture through which fluids being
circulated in the wellbore can undesirably pass from the wellbore into the subterranean formation. In other
embodiments, the permeable zone allows a formation fluid such as water to pass from the surrounding
formation into the wellbore and thus form crossflows in fluids residing in the wellbore such as a cement
slurry before it sets. In a permeable zone, the average size of the openings of the fluid flow paths is herein
referred to as an average fracture width of the permeable zone. In embodiments, the average fracture width
of a permeable zone is W. In embodiments, W is from about 10 microns to about 5000 microns,
alternatively from about 10 microns to about 4000 microns, alternatively from about 20 microns to about
3500 microns or alternatively from about 30 microns to about 3000 microns.
[0013] A WSF as disclosed herein can comprise a particulate blend and water. The particulate blend
can comprise a type A particulate material and a type B particulate material where the type A particulate
material is characterized by a weight average particle size of equal to or greater than about W /3 microns,
and the type B particulate material is characterized by a weight average particle size of less than about W /3
microns.
[0014] In embodiments, the type B particulate material is harder than the type A particulate material.
In embodiments, the type B particulate material is characterized by a Mohs hardness of equal to or greater
than about 3, alternatively equal to or greater than about 3.5 or alternatively equal to or greater than about 4.
The type A particulate material can be characterized by a Mohs hardness of less than about 4, alternatively
less than about 3 .5, alternatively less than about 3, alternatively less than about 2.8 or alternatively less than
about 2.6.
[0015] The type A particulate material and the type B particulate material can be compositionally
different. Examples of the type A particulate material include, but are not limited to graphite, calcined
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petroleum coke, ground laminate, ground tires, ground nut shells, mica particles, polypropylene fibers, and
polymeric beads. Examples of the type B particulate material include, but are not limited to calcium
carbonate (e.g., ground marble), glass particles, sand, ceramic particles, and ground battery casings.
Commercial examples of the type B particulate material include but are not limited to BARACARB® 5
sized-calcium carbonate, BARACARB® 25 sized-calcium carbonate, BARACARB® 50 sized-calcium
carbonate, and BARACARB® 150 sized-calcium carbonate, which are commercially available from
Halliburton Energy Services, Inc.
[0016] The particulate blend can have a physical shape of platelets, shavings, fibers, flakes, ribbons,
rods, strips, spheroids, toroids, pellets, tablets, or any other physical shape. The particulate blend can have a
multimodal particle size distribution. The particulate blend having a multimodal particle size distribution
may have a bimodal particle size distribution, a trimodal particle size distribution, or other suitable particle
size distribution as desired, inter alia, on a particular application. In embodiments, the particulate blend
comprises a first portion of particulate material having a weight average particle size in a range of from
about 4000 microns to about 5000 microns, a second portion of particulate material having a weight average
particle size in a range of from about 1000 microns to about 4000 microns, and a third portion of particulate
material having a weight average particle size in the range of from about 10 microns to about 1000 microns.
[0017] In embodiments, the type A particulate material has a weight average particle size of from
about 170 microns to about 1700 microns, alternatively from about 170 microns to about 1400 microns,
alternatively from about 190 microns to about 1400 microns or alternatively from about 220 microns to
about 1400 microns. The type B particulate material can have a weight average particle size of from about 3
microns to about 1000 microns, alternatively from about 3 microns to about 800 microns, alternatively from
about 3 microns to about 600 microns, alternatively from about 3 microns to about 400 microns,
alternatively from about 3 microns to about 240 microns, alternatively from about 3 microns to about 170
microns, alternatively from about 10 microns to about 170 microns or alternatively from about 10 microns
to about 150 microns.
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[0018] Sufficient amounts of particulate blend including type A particulate material and type B
particulate material can be added to the WSF to improve the effectiveness of the WSF in reducing or
preventing circulation losses and withstanding increased pressures. A total amount of the particulate blend
in the WSF can be from about 3 wt.% to about 25 wt.% based on the total weight of the WSF, alternatively
from about 5 wt.% to about 20 wt.% or alternatively from about 5 wt.% to about 15 wt.%. In embodiments,
a total amount of the particulate blend in the WSF is from about 3 lb per barrel (lb/bbl) to about 60 lb/bbl
based on the total volume of the WSF, alternatively from about 4 lb/bbl to about 60 lb/bbl or alternatively
from about 4 lb/bbl to about 55 lb/bbl. In embodiments, the weight ratio of type A particulate material to
type B particulate material is from about 0. 05 to about 5, alternatively from about 0.1 7 to about 5 or
alternatively from about 1 to about 4.
[0019] The WSF can comprise water. The water can be selected from a group consisting of
freshwater, seawater, saltwater, brine (e.g., underground natural brine, formulated brine, etc.), and
combinations thereof. A formulated brine may be produced by dissolving one or more soluble salts in
water, a natural brine, or seawater. Representative soluble salts include the chloride, bromide, acetate, and
formate salts of potassium, sodium, calcium, magnesium, and zinc. Generally, the water may be from any
source, provided that it does not contain an amount of components that may undesirably affect the other
components in the WSF. The water can be present in the WSF in an amount effective to provide a slurry
having desired (e.g., job or service specific) rheological properties. The water can be present in the WSF in
an amount of from about 20 wt.% to about 95 wt.% based on the total weight of the WSF, alternatively from
about 25 wt.% to about 95 wt.% or alternatively from about 30 wt.% to about 95 wt.%.
[0020] In embodiments, the WSF further comprises a cementitious material and can be referred to as
a cementitious fluid. The cementitious material can comprise calcium, aluminum, silicon, oxygen, iron,
and/or sulfur. In embodiments, the cementitious material comprises Portland cement, pozzolana cement,
gypsum cement, shale cement, acid cement, base cement, phosphate cement, high alumina content
cement, slag cement, silica cement, high alkalinity cement, magnesia cement, or combinations thereof.
Portland cements that are suited for use in the disclosed WSF include, but are not limited to, Class A, C,
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G, H, low sulfate resistant cements, medium sulfate resistant cements, high sulfate resistant cements, or
combinations thereof. The class A, C, G, and H cements are classified according to API Specification 10.
In embodiments, "high alumina content cement" refers to a cement having an alumina concentration in the
range of from about 40 wt.% to about 80 wt.% by a weight of the high alumina content cement. In
embodiments, "high alkalinity cement" refers to a cement having a sodium oxide concentration in the range
of from about 1.0 wt.% to about 2.0 wt.% by a weight of the high alkalinity cement.
[0021] The cementitious material can be present in the WSF in an amount of from about 30 wt.% to
about 80 wt.% based on the total weight ofthe WSF, alternatively from about 35 wt.% to about 75 wt.%
or alternatively from about 40 wt.% to about 70 wt.%.
[0022] In embodiments, the WSF further comprises a gelling agent. Nonlimiting examples of gelling
agents suitable for use in the present disclosure include locust bean gum, Karaya gum, gum tragacanth,
hydrophobically modified guars, high-molecular weight polysaccharides composed of mannose and
galactose sugars, heteropolysaccharides obtained by fermentation of starch-derived sugars, xanthan, pectins,
diutan, welan, gellan, scleroglucan, chitosan, dextran, substituted or unsubstituted galactomannans, starch,
cellulose, cellulose ethers, carboxycelluloses, hydroxypropyl cellulose, carboxyalkylhydroxyethyl
celluloses, carboxymethyl hydroxyethyl cellulose, methyl cellulose, sodium polyacrylate, polyacrylamide,
partially hydrolyzed polyacrylamide, polymethacrylamide, poly(acrylamido-2-methyl-propane sulfonate),
poly(sodium-2-acrylamide-3-propylsulfonate ), copolymers of acrylamide and acrylamido-2-methyl-propane
sulfonate, terpolymers of acrylamido-2-methyl-propane sulfonate, acrylamide and vinylpyrrolidone or
itaconic acid, and combinations thereof.
[0023] In embodiments, the gelling agent has a molecular weight in a range of from equal to or
greater than about 0.5 MM g/mol to equal to or less than about 5 MM g/mol, alternatively from equal to
or greater than about 0.8 MM g/mol to equal to or less than about 5 MM g/mol, alternatively from equal
to or greater than about 1.0 MM g/mol to equal to or less than about 5 MM g/mol, which can be measured
by Gel Permeation chromatography (GPC). The gelling agent can be present in the WSF in an amount of
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from about 0.001 wt.% to about 5 wt.%, based on the total weight ofthe WSF, alternatively from about
0.001 wt.% to about 4 wt.% or alternatively from about 0.01 wt.% to about 3 wt.%.
[0024] In embodiments, the WSF further comprises a fluid loss control additive. The fluid loss control
additive can comprise a polymer of methacrylates, methyl acrylate, ethyl acrylate, 2-chloroethyl vinyl ether,
2-ethylhexyl acrylate, hydroxyethyl methacrylate, butyl acrylate, butyl methacrylate, trimethylolpropane
triacrylate (TMPTA), acrylamide, N-N dimethyl acrylamide, 2-Acrylamido-2-methylpropane sulfonic
acid (AMPS), N-vinyl pyrrolidone, acryloylrnorpholine, or combinations thereof. The fluid loss control
additive can be present in the WSF in an amount of from about 0.001 wt.% to about 10 wt.% based on the
total weight ofthe WSF, alternatively from about 0.01 wt.% to about 9 wt.% or alternatively from about
0.1 wt.% to about 8 wt.%.
[0025] The WSF can further comprise clay. The clay can comprise a natural clay, a synthetic clay, or
combinations thereof. In embodiments, the clay comprises bentonite, sodium bentonite, montmorillonite,
beidellite, nontronite, hectorite, samonite, smectite, kaolinite, serpentine, illite, chlorite, montmorillonite,
saponite, sepiolite, fuller's earth, attapulgite, or combinations thereof. The clay can be present in the WSF
in an amount of from about 1 wt.% to about 20 wt.% based on the total weight of the WSF, alternatively
from about 2 wt.% to about 15 wt.% or alternatively from about 3 wt.% to about 10 wt.%.
[0026] The WSF can further comprise a pH adjusting agent. The pH adjusting agent can be a base, an
acid, or a buffer. Nonlimiting examples of bases suitable for use in the present disclosure include
ammonium, alkali metal, and alkaline earth metal carbonates and bicarbonates, such as Na2C03, K2C03,
CaC03, MgC03, NaHC03, and KHC03; alkali and alkaline earth metal oxides, such as BaO, SrO, Li20,
CaO, Na20, K20, and MgO; ammonium, alkali metal, and alkaline earth metal hydroxides, such as NaOH,
NH40H, KOH, LiOH, and Mg(OHh; and alkali and alkaline earth metal phosphates, such as Na3P04 and
Ca3(P04)2. Nonlimiting examples of acids suitable for use in the present disclosure include mineral acids
such as hydrochloric acid, sulphuric acid, sulphonic acid, and sulphamic acid; organic acids such as tartaric
acid, citric acid, formic acid, acetic acid, monochloroacetic acid, dichloroacetic acid, trichloroacetic acid,
sulphinic acid, methanesulfonic acid, lactic acid, glycolic acid, oxalic acid, propionic acid, and butyric acid;
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ammonium salts and salts of weak bases, such as organic amines; or combinations thereof. The buffer can
comprise a combination of weak acids or weak bases, in combination with the corresponding salts to
maintain the pH of a fluid in a desired range. Nonlimiting examples of chemical combinations which can be
used as buffers include acetic acid/sodium acetate, sodium carbonate/sodium bicarbonate, and sodium
dihydrogen phosphate/sodium monohydrogen phosphate.
[0027] In embodiments, the pH adjusting agent may be present in the WSF in a suitable amount that
will provide a desired pH. The pH adjusting agent can be present in the WSF in an amount of from about 1
wt.% to about 15 wt.% based on the total weight of the WSF, alternatively from about 1 wt.% to about 10
wt.% or alternatively from about 1 wt.% to about 5 wt.%.
[0028] The WSF can further comprise one or more additives. The one or more additives can be
included in the WSF for improving or changing the properties thereof. The one or more additives can
comprise a viscosifier, an emulsifier, a defoamer, an expansion agent, a salt, a corrosion inhibitor, a mutual
solvent, a breaking agent, a relative permeability modifier, a crosslinker, a flocculant, a water softener, an
oxidation inhibitor, a thinner, a scavenger, a gas scavenger, a lubricant, a friction reducer, a bridging agent, a
vitrified shale, a thixotropic agent, a dispersing agent, a weight reducing additive, a heavyweight additive, a
surfactant, a scale inhibitor, a clay control agent, a clay stabilizer, a silicate-control agent, a biocide, a
biostatic agent, a storage stabilizer, a filtration control additive, a suspending agent, a foaming agent, latex
emulsions, a formation conditioning agent, elastomers, gas/fluid absorbing materials, resins, superabsorbers,
mechanical property modifying additives, inert particulates, and the like, or combinations thereof. The one
or more additives can be present in the WSF in an amount of from about 0 wt.% to about 15 wt.% based on
the total weight of the WSF, alternatively from about 1 wt.% to about 12 wt.% or alternatively from 2 wt.%
to about 10 wt.%.
[0029] In embodiments, the WSF can have a density of from about 7 pounds per gallon (lb/gal) to
about 20 lb/gal, alternatively from about 7 lb/gal to about 15 lb/gal or alternatively from about 7 lb/gal to
about 13 lb/ gal.
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[0030] A WSF of the type disclosed herein can be used to minimize fluid loss in operation. For
example, the WSF can have an actual fluid loss of from about 10 ml per 30 minutes to about 80 ml per 30
minutes on a 60 mesh screen, alternatively from about 10 ml per 30 minutes to about 75 ml per 30 minutes
or alternatively from about 15 ml per 30 minutes to about 75 ml per 30 minutes, at about 180 °F when
measured in accordance with test standard API-RP-10B-2. The actual fluid loss refers to fluid loss in
milliliter (ml) that is actually collected in the measurement. In embodiments, the WSF can have an actual
fluid loss of from about 10 ml per 3 0 minutes to about 80 ml per 3 0 minutes on a slot with a width of about
W microns, alternatively from about 10 ml per 30 minutes to about 75 ml per 30 minutes or alternatively
from about 15 ml per 30 minutes to about 75 ml per 30 minutes, at about 180 °F when measured in
accordance with test standard API-RP-10B-2.
[0031] In embodiments, a WSF of the type disclosed herein has an actual fluid loss of from about 20
ml per 30 minutes to about 120 ml per 30 minutes on a 60 mesh screen, alternatively from about 30 ml per
30 minutes to about 100 ml per 30 minutes or alternatively from about 30 ml per 30 minutes to about 90 ml
per 30 minutes, at about 300 °F when measured in accordance with test standard API-RP-10B-2. In
embodiments, the WSF has an actual fluid loss of from about 20 ml per 30 minutes to about 120 ml per 30
minutes on a slot with a width of about W microns, alternatively from about 30 ml per 30 minutes to about
100 ml per 30 minutes or alternatively from about 30 ml per 30 minutes to about 90 ml per 30 minutes, at
about 300 °F when measured in accordance with test standard API-RP-10B-2.
[0032] A WSF of the type disclosed herein can be prepared using any suitable method. In
embodiments, the method comprises placing a mixture including a particulate blend of the type disclosed
herein and water into a suitable container (e.g., a mixer, a blender) and blending the mixture until the
mixture becomes a pumpable fluid (e.g., a homogeneous fluid). The container can be any container that is
compatible with the mixture and has sufficient space for the mixture. A blender or mixer can be used for
blending/mixing the mixture.
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[0033] The WSF can be prepared at the wellsite. For example, the solid composition (e.g., the
particulate blend, one or more additives) ofthe WSF can be transported to the wellsite and combined (e.g.,
mixed/blended) with water located proximate the wellsite to form the WSF. The solid composition of the
WSF can be prepared at a location remote from the wellsite and transported to the wellsite, and, if
necessary, stored at the on-site location. When it is desirable to prepare the WSF on the wellsite, the solid
composition of the WSF along with additional water and optional other additives can be added into a
container (e.g. a blender tub, for example mounted on a trailer), and the mixture is then blended until the
mixture becomes a pumpable fluid (e.g., a homogeneous fluid). Additives can be added to the WSF during
preparation thereof(e.g., during blending) and/or on-the-fly (e.g., in real time or on-location) by addition to
(e.g., injection into) the WSF when being pumped into the wellbore.
[0034] The WSF disclosed herein (i.e., comprising a particulate blend of Type A and Type B
particulate materials) can be used as a spacer fluid to physically separate two or more fluids present in a
wellbore. The spacer fluid can be placed between two fluids (the first fluid and the second fluid) contained
or to be pumped within a wellbore. The spacer fluid can physically space the first fluid apart from the
second fluid such that the first fluid and the second fluid do not comingle while being placed (e.g., pumped)
into the wellbore. In embodiments, the spacer fluid can be used to space apart two fluids (e.g., drilling
fluid/mud and a cementitious fluid) that are being flowed from the surface down through a conduit (e.g.,
casing) present in the wellbore, exiting the conduit and flowing back upward in the annular space between
the outside conduit wall and interior face of the wellbore. In embodiments, the spacer fluid can be used to
space apart two fluids (e.g., drilling fluid/mud and a cementitious fluid) that are being flowed from the
surface down through the annular space between the outside conduit wall and interior face of the well bore,
exiting the annular space and flowing back upward through the inside of the conduit.
[0035] In embodiments, the spacer fluid can be placed into a wellbore to separate a drilling fluid from
a cementitious fluid. There can be a conduit inside the wellbore forming an annular space between an
outside wall of the conduit and the wall of the wellbore. The conduit can be casing. In embodiments, at
least a portion of the annular space comprises a permeable zone having an average fracture width of about
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W microns. A method of the present disclosure can further comprise: circulating the spacer fluid down
through the conduit and back up through the annular space. In other embodiments, the direction of the
circulating reverses and circulating the spacer fluid occurs down through the annular space and back up
through the conduit. At least a portion of the particulate blend in the spacer fluid of the type disclosed
herein is placed with the permeable zone.
[0036] Also disclosed herein is a method of servicing a wellbore with a conduit (e.g., casing) disposed
therein. In embodiments, an outer surface of the conduit and the wellbore wall form an annular space. At
least a portion of the wellbore wall within the annular space comprises a permeable zone having an average
facture width of about W microns. A first fluid can be present in at least a portion of the annular space
proximate the permeable zone. The first fluid can be a drilling fluid. The drilling fluid herein refers to any
liquid and gaseous fluid and mixtures of fluids and solids used in operations of drilling a borehole into the
earth. The drilling fluid can be water based, non-water based, and/or gaseous. In embodiments, the method
further comprises placing a spacer fluid of the type disclosed herein (i.e., comprising a particulate blend of
Type A and Type B particulate materials) into at least a portion of the annular space and displacing at least a
portion of the first fluid from the annular space, wherein the spacer fluid comprises a particulate blend of the
type disclosed herein and water. In embodiments, the method further comprises placing a cementitious fluid
into at least a portion of the annular space and displacing at least a portion of the spacer fluid from the
annular space. In embodiments, the method as disclosed herein can further comprise allowing at least a
portion of the cementitious fluid to set.
[0037] Disclosed herein is a method of servicing a wellbore 101 penetrating a subterranean formation
as shown in FIGS. lA and lB. The wellbore 101 has a conduit 102 disposed therein forming an annular
space between an outer wall of the conduit 102 and an inner wall of the well bore 101. At least a portion of
the inner wall of the wellbore 1 01 within the annular space comprises a permeable zone 1 06 having an
average fracture width of about W microns. The inner flow bore of the conduit 102 and! or annular space
may comprise a first fluid 103, for example a drilling fluid or mud, which may be circulated or static prior to
pumping of a spacer fluid followed by a second fluid (e.g., cement slurry). In embodiments, the method
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comprises pumping a spacer fluid 104 followed by a second fluid 105 from the surface down an inner flow
bore of the conduit 102, out an end of the conduit 102, and back up the annular space toward the surface,
wherein the first fluid 103 is displaced from the conduit 102 and/or the annular space during the pumping.
In some embodiments, the method comprises pumping the first fluid 103 followed by a spacer fluid 104
followed by a second fluid 105 from the surface down an inner flow bore of the conduit 102, out an end of
the conduit 102, and back up the annular space toward the surface, wherein the first fluid 103 is displaced
from the conduit 102 and/or the annular space during the pumping. The pumping of the first fluid, spacer
fluid, and/or third fluid may be continuous or intermittent (e.g., paused to allow time for the particulate
material in the spacer fluid to travel/migrate into the permeable zone 1 06). The spacer fluid 104 comprises
a particulate blend and water. The particulate blend in the spacer fluid 104 comprises a type A particulate
material and a type B particulate material. The type A particulate material can be characterized by a weight
average particle size of equal to or greater than about W /3 microns, while the type B particulate material can
be characterized by a weight average particle size of less than about W /3 microns. The weight ratio of the
type A particulate material to the type B particulate material can be from about 0.05 to about 5. In
embodiments, at least a portion of the particulate blend is placed with the permeable zone 106 having an
average fracture width of about W microns. The conduit 102 can comprise casing. In embodiments, the
first fluid 103 can be a drilling fluid, and the second fluid 105 can be a cementitious fluid.
[0038] In embodiments, the direction of the flow ofthe first fluid, the spacer fluid, and the second fluid
can reverse from that in the method disclosed above. Disclosed herein is a method of servicing a wellbore
101 penetrating a subterranean formation as shown in FIGS. 2A and 2B. The wellbore 101 has a conduit
102 disposed therein. The conduit 102 has an inner flow bore. An outer wall of the conduit 102 and an
inner wall of the wellbore 101 form an annular space. At least a portion of the inner wall of the wellbore
101 within the annular space comprises a permeable zone 106 having an average fracture width of about W
microns. The inner flow bore of the conduit 102 and/or annular space may comprise a first fluid 103, for
example a drilling fluid or mud, which may be circulated or static prior to pumping of a spacer fluid
followed by a second fluid (e.g., cement slurry). In embodiments, the method comprises pumping a spacer
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fluid 104 followed by a second fluid 105 from the surface down through the annular space, out an end of the
annular space, and back up the inner flow bore toward the surface, wherein the first fluid 103 is displaced
from the conduit 102 and/or the annular space during the pumping. In some embodiments, the method
comprises pumping a first fluid 103 followed by a spacer fluid 104 followed by a second fluid 105 from the
surface down through the annular space, out an end of the annular space, and back up the inner flow bore
toward the surface, wherein the first fluid 103 is displaced from the conduit 102 and/or the annular space
during the pumping. The pumping of the first fluid, spacer fluid, and/or third fluid may be continuous or
intermittent (e.g., paused to allow time for the particulate material in the spacer fluid to travel/migrate into
the permeable zone 1 06). The spacer fluid 104 comprises a particulate blend and water. The particulate
blend in the spacer fluid 104 comprises a type A particulate material and a type B particulate material. The
type A particulate material can be characterized by a weight average particle size of equal to or greater than
about W /3 microns, while the type B particulate material can be characterized by a weight average particle
size of less than about W /3 microns. The weight ratio of the type A particulate material to the type B
particulate material can be from about 0.05 to about 5. In embodiments, at least a portion of the particulate
blend is placed with the permeable zone 106 having an average fracture width of about W microns. The
conduit 102 can comprise casing. In embodiments, the first fluid 103 can be a drilling fluid, and the second
fluid 105 can be a cementitious fluid.
[0039] In embodiments, the WSF of the type disclosed herein (i.e., comprising a particulate blend of
Type A and Type B particulate materials) can be used as a cementitious fluid, for example by adding a
cementitious material of the type disclosed herein. The method of the present disclosure can comprise
placing the cementitious fluid into the wellbore proximate a permeable zone and allowing at least a portion
of the cementitious fluid to set. The cementitious fluid can be used to permanently seal the annular space
between the conduit (e.g., casing) and the wellbore wall. The cementitious fluid can also be used to seal
formations to prevent loss of drilling fluid (e.g., in squeeze cementing operations) and for operations ranging
from setting kick-off plugs to plug and abandonment of a wellbore. In embodiments, a cementitious fluid of
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the type disclosed herein can be prepared by mixing cement, the particulate blend as disclosed herein, water,
and suitable additives to form a pumpable slurry.

CLAIMS
What is claimed is:
1. A method of servicing a wellbore penetrating a subterranean formation, comprising:
placing a wellbore servicing fluid (WSF) into the wellbore proximate a permeable zone having
an average fracture width of about W microns,
wherein the WSF comprises a particulate blend and water, and
wherein the particulate blend comprises (a) a type A particulate material
characterized by a weight average particle size of equal to or greater than about W/3
microns, and (b) a type B particulate material characterized by a weight average particle
size of less than about W/3 microns, wherein a weight ratio of the type A particulate
material to the type B particulate material is from about 0.05 to about 5.
2. The method of claim 1, wherein W is from about 10 microns to about 5000 microns.
3. The method of claim 1, wherein the WSF is a drilling fluid, a lost circulation fluid, a
spacer fluid, a cement fluid, or a completion fluid.
4. The method of claim 1, wherein the type A particulate material is characterized by a
Mohs hardness of less than about 4.
5. The method of claim 1, wherein the type B particulate material is characterized by a
Mohs hardness of equal to or greater than about 3.
6. The method of claim 1, wherein the type B particulate material is calcium carbonate.
7. The method of claim 1, wherein the particulate blend is present in the WSF in an amount
of from about 3 wt.% to about 25 wt.% based on a total weight of the WSF.
8. The method of claim 1, wherein the water is present in the WSF in an amount of from
about 20 wt.% to about 95 wt.% based on a total weight of the WSF.

9. The method of claim 1, wherein the WSF further comprises a cementitious material.
10. The method of claim 1, wherein at least a portion of the particulate blend is placed with
the permeable zone having an average fracture width of about W microns.
11. A method of servicing a wellbore with casing disposed therein to form an annular space
between a wellbore wall and an outer surface of the casing, wherein at least a portion of the
wellbore wall within the annular space comprises a permeable zone having an average facture
width of about W microns, wherein a first fluid is present in at least a portion of the annular
space proximate the permeable zone, comprising:
placing a spacer fluid into at least a portion of the annular space and displacing at least a
portion of the first fluid from the annular space, wherein the spacer fluid comprises a particulate
blend and water,
wherein the particulate blend comprises (a) a type A particulate material
characterized by a weight average particle size of equal to or greater than about W/3
microns, and (b) a type B particulate material characterized by a weight average particle
size of less than about W/3 microns, wherein a weight ratio of the type A particulate
material to the type B particulate material is from about 0.05 to about 5; and
placing a cementitious fluid into at least a portion of the annular space and displacing at
least a portion of the spacer fluid from the annular space.
12. The method of claim 11, wherein the first fluid is a drilling fluid.
13. The method of claim 1, wherein at least a portion of the particulate blend is placed with
the permeable zone having an average fracture width of about W microns to reduce an inflow of
fluid from a formation into the wellbore and/or reduce an outflow of fluid from the wellbore into
the formation.

14. A method of treating a subterranean formation penetrated by a wellbore, comprising:
drilling the wellbore with a drill bit connected to drill pipe;
determining a location of a lost circulation zone in an uncased portion of the wellbore,
wherein the lost circulation zone has an average fracture width of about W microns;
discontinuing drilling;
introducing, via a drill pipe, a WSF at the location proximate the lost circulation zone,
wherein the WSF comprises a particulate blend and water,
wherein the particulate blend comprises (a) a type A particulate material
characterized by a weight average particle size of equal to or greater than about W/3
microns, and (b) a type B particulate material characterized by a weight average particle
size of less than about W/3 microns, wherein a weight ratio of the type A particulate
material to the type B particulate material is from about 0.05 to about 5;
allowing the WSF to flow into at least a portion of the lost circulation zone to place the
particulate blend into the lost circulation zone;
allowing the particulate blend to block at least a portion of the lost circulation zone; and
resuming drilling of the wellbore.
15. The method of claim 9, further comprising allowing at least a portion of the WSF to set.