Note: Descriptions are shown in the official language in which they were submitted.
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COMPOSITIONS AND METHODS FOR TREATMENT OF WELL BORE TAR
BACKGROUND
[00011 The present invention relates to methods and compositions for use in
subterranean operations. More particularly, the present invention relates to
tar stabilizing
polymers used to treat tar resident in a well bore and associated methods of
use.
[0002] Many subterranean operations involve the drilling of a well bore
from the surface through rock, and/or soil to penetrate a subterranean
formation containing
fluids that are desirable for production. In the course of drilling operations
and other
subterranean operations, the drillstring and/or other equipment may come into
contact with
zones of rock and/or soil containing tar (e.g., heavy hydrocarbons, asphalt:,
and bitumens); in
many such operations, it may be desirable to drill the well bore through these
tar-containing
zones. However, tar is a relatively tacky substance that may readily adhere to
any surface
that it contacts, including the surfaces of the well bore and/or any
equipment: utilized during
the drilling operation. Tar also may dissolve into many synthetic treatment
fluids used in the
course of drilling operations, increasing the tacky and adhesive properties of
the tar. If a
sufficient amount of tar adheres to surfaces in the well bore or drilling
equipment, it may,
among other problems, prevent the drillstring from rotating, prevent fluid
circulation, or
otherwise impede the effectiveness of a drilling operation. In some eases, it
may become
necessary to remove andlor disassemble the drillstring in order to remove
accretions of tar, a
process which may create numerous cost and safety concerns. The accretion of
tar on
drilling equipment and/or in the well bore also can impede any subsequent
operations
downhole, including cementing, acidizing, fracturing, sand control, and
remedial treatments,
in addition, soft, tacky tar that manages to reach the surface may foul
surface equipment,
including solids screening equipment,
100031 Existing methods of managing these problems that result from well
bore tar incursion may be problematic. Some of these methods involve effecting
an increase
in hydrostatic pressure in the well bore so as to force the tar out of the
well bore to the
surface. However, this increased hydrostatic pressure may damage the well bore
and/or a
portion of the subterranean tOrmation. Other conventional methods utilize
treatment fluids
that comprise dispersants, surfactants, andior solubilizers. which allow the
tar particles to
dissolve in or homogenize with the treatment fluids. However, the tar
particles may- not be
readily separated out of the fluid once they have dissolved into or homogenind
with the
fluid. he
presence of the tar particles in the treatment fluid may alter its rheologieal
properties andlor suspension capacity, which may limit its use in subsequent
operations.
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Moreover, the addition of these dispersants, surtiletants, and solubilizers
may increase the
complexity and cost of the drilling operation.
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SUMMARY
[0004] The present invention relates to methods and compositions for use in
subterranean operations. More particularly, the present invention relates to
tar stabilizing
polymers used to treat tar resident in a well bore and associated methods
fuse.
[00051 An embodiment of the present invention provides a method fir
treatment of well bore tar. The method may comprise contacting tar resident in
a well bore
with a tar stabilizing polymer comprising at least one polymer selected from
the group
consisting of a styrene polymer, an acrylate polymer, a styrene-acrylate
polymer, and any
combination thereof. The method may further comprise allowing the tar
stabilizing polymer
to interact with the tar to at least partially reduce the tendency of the tar
to adhere to a
surface.
[0006] Another embodiment of the present invention provides a method for
treatment of well bore tar. The method may comprise using a drill bit to
enlarge a well bore
in a subterranean formation comprisirm tar. 'the method may further comprise
circulating a
drilling fluid past the drill bit to remove cuttings from the drill bit,
wherein the drilling fluid
comprises an aqueous fluid and a tar stabilizing polymer comprising at least
one polymer
selected from the group consisting of a styrene polymer, an acrylate polymer,
a styrene-
acrylate polymer, and any combination thereof
[0007] Yet another embodiment of the present invention provides a
treatment fluid. The treatment fluid may comprise an aqueous fluid. -The
treatment fluid
may further comprise a tar stabilizing polymer comprising at least one polymer
selected from
the group consisting of a styrene polymer, an acrylate polymer, a styrene-
acrylate polymer,
and any combination thereof,
[00081 The features and advantages of the present invention will be readily
apparent to those skilled in the art. While numerous changes may be made by
those skilled
in the art, such changes are within the spirit of the invention.
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DESCRIPTION OF PREFERRED EMBODIMENTS
[00091 The present invention relates to methods and compositions for use in
subterranean operations. More particularly, the present invention relates to
tar stabilizing
polymers used to treat tar resident in a well bore and associated methods of
use. As used
S
herein, the term "tar stabilizing polymer' refers to a polymer that can
interact with tar
resident in a well bore such that the tar becomes less tacky and/or less able
to adhere to a
surface. One of the many advantages of the present invention, many of which
are not
discussed or alluded to herein, is that tar treated by the compositions and
methods disclosed
herein may be substantially less tacky and/or less able to adhere to a
surtlice. As a result, tar
treated in this manner may be susceptible to screen separation from treatment
fluids, drill
cuttings, tar sands, and the like.
[00101 Embodiments of the present invention disclose tar stabilizing
polymers comprising a styrene polymer, an acrylatc polymer, a styrene-acrylate
polymer, or
any combination thereof The suitable tar stabilizing polymers generally can be
emulsified
in an aqueous fluid in accordance with present embodiments. In some
embodiments. the tar
stabilizing polymers may be ionic or nonionic in nature. In certain
embodiments, the tar
stabilizing polymers may interact with the tar resident in a well bore such
that the properties
of the tar are altered. in certain embodiments, the tar stabilizing polymers
may bind or coat
the tar such that the tar becomes less sticky.
100111 Examples of styrene polymers that may be suitable for use in
embodiments of the present invention include, but are not limited to, styrene
copolymers
which include co-monomers of styrene or any derivative thereof In some
embodiments, the
styrene polymer may be made by polymerizing styrene, which may be substituted
or
unsubs-tituted. The styrene may be substituted with any number of different
groups that will
be evident to those of ordinary skill in the art, including without limitation
chloro groups,
bromo groups, fluor() groups. alkyl groups, alkoxy groups, alkenyl groups,
alkynyl groups,
aryl groups, and substituted versions thereof Combinations of styrene polymers
may also be
suitable, in Certain embodiments. in some embodiments, the styrene polymer may
comprise
styrene in an amount in a range of about 90% to about 100% by weight of the
styrene
polymer, about 95% to about 100% by weight of the styrene polymer, or about
99% to about
100% by weight of the styrene polymer. In one embodiment, the styrene polymer
may
consist of styrene. In some embodiments, the styrene polymer may be
essentially free of
acry la te and/or acrylic acid.
[00121 F...xamples of amdate polymers that may be suitable =for use in
embodiments of the present invention include, but are not 'limited to,
aerylate copolymers
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which include co-monomers of acrylate or any derivative thereof. The acrylate
may be
substituted with any number of different groups that will be evident to those
of ordinary skill
in the art, including without limitation chloro groups, bromo groups, fluor()
groups, alkyl
groups, alkoxy groups, alkertyl groups, alkynyl groups, aryl groups, and
substituted versions
thereof In accordance with present embodiments, the acrylate may comprise two
or more
units individually selected from the group consisting of -acrylate, -
methaerylate, -
ethylacrylate, -propylacrylate, -butylacrylate, -h-w-butyl-acrylate, -n-
hydroxyethyl
methacryiate, -potassium acrylate, -pentabromobenzyl acrylate., -methyl
methactyiale, -ethyl
methacrylate, -n-nitrophenyl acrylate, -.methyl 2-(acyloxymethyl)acrylate, -
cyclohexyl
acrylate, -n-ethylhexyl acrylate, any derivative thereof: Combinations of
aerviate polymers
may also be suitable, in certain embodiments. In some embodiments, the
acrylate polymer
may be formed by polymerizing acrylic acid, which may be subsequently
neutralized to form
the acrylate copolymer. In some embodiments, the acrylate polymer may comprise
acrylate
in an amount in a range of about 90% to about 100% by weight of the acrylate
polymer,
about 95% to about 100% by weight of the acrylate polymer, or about 99% to
about 100%
by weight of the acrylate polymer. In one embodiment, the acrylate polyiner
may consist of
acrylatc. In some embodiments, the acrylate polymer may be essentially free of
styrene.
[00131 Examples of Styrene-acrylate polymers that may be suitable for use
in embodiments of the present invention may include, but are not limited to,
styrene-aerylate.
copolymers and mixed copolymers which include at least one unit comprising
styrene, a
substituted styrene, and any derivative thereof; and at least one comprising -
acrylate. -
methaerylate, -ethyl a c rvl ote, ropyl tic ry la te, -
butyl tic ry e, ell- btity ry ate. -ii-
hvdroxyethxl methacrylate, -potassium acrylate, -pentabromobenz.y1 acrylate. -
methyl
methaerylate, -ethyl methaerylate, -n-nitrophenyl
acrylate, -methyl
2.5 tacyloxymethx..1)acry1ate, -cyclohexyl acrylate, -n-ethylhexyl
acrylate, or any derivative
thereof: Combinations of suitable styrene-acrylate polymers may also be
suitable, in certain
embodiments.
[0014] in some embodiments, the tar stabilizing polymers may be provided
in the form of a latex emulsion or a powder. For example, a latex emulsion may
be used that
comprises the tar stabilizing polymer. In some embodiments, the latex emulsion
may be in
the range front about 5% to about 60% active by weight. In some embodiments,
the latex
emulsion ma have a p11 in the range of about 2 to about 4. The latex emulsion
may further
comprise a surfactant. Generally, any surfactant that will emulsify andior
suspend the tar
stabilizing. polymers mt.o.,, be used in embodiments of the fluids ot: the
present invention. In
certain embodiments, it may be cksirable to select a surlatint. that will not
emulsify the tar
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Sotii.tht to be treated, In certain embodiments, the surfactants may be
present in an amount
sufficient to emulsify' and/or suspend the tar stabilizing polymers. This
amount may depend
on, among other things, the type of surfactant used and the amount of tar
stabilizing polymer
to be emulsified and/or suspendedõA person of ordinary skill in the art will
recognize, with.
the benefit of this disclosure, the type and amount of surtactant that should
be added kir a
particular application. In another embodiment, the tar stabilizing polymers
may be provided
in the form of a powder that can, for example, be dispersed in water, In some.
embodiments,
the far stabilizing polymer may have, fOr example, a particle size of less
than about I micron,
less than about 500 nanometers, or less than about 100 nanometers.
[00151 In accordance with present embodiments, one or more of the tar
stabilizing polymers may be included in a treatment fluid as described herein.
As used
herein, the term "treatment fluid" refers to any fluid that may be used in a
subterranean
application in conjunction with a desired function and/or for a desired
purpose. The term
"treatment fluid" does not imply any particular action by the fluid or any
component thereof.
Treatment fluids may be used, for example, to drill, complete, work over,
fracture, repair, or
in any way prepare a well bore for recovery of materials residing in a
subterranean formation
penetrated by the well bore. Examples of treatment fluids include, but are not
limited,
cement compositions, drilling fluids, spacer fluids, and spotting fluids.
1001.6J In some embodiments, at least one tar stabilizing polymer may be
included in a treatment fluid in a quantity sufficient to treat the tar in the
well bore. In
certain embodiments, the concentration of the tar stabilizing polymer in the
treatment fluid
may be at least about Ms by volume of the fluid, and up to an amount such that
the tar
stabilizing polymer will precipitate out of the fluid. In
certain embodiments, the
concentration of tar stabilizing polymer in the treatment fluid may be in the
range of from
about l% to about 70'!4i by volume of the fluid. In certain embodiments, the
concentration of
tar stabilizing polymer in the treatment fluid may be in the range for from
about I% to about
10% by volume of the fluid. In certain embodiments, the tar stabilizing
polymer may be
added to the treatment fluid in the form of' a latex-type emulsion or as
dispersed particles.
One of ordinary skill in the art, with the benefit of this disclosure, will be
able to determine
the appropriate concentration of the tar stabilizing polymer in the fluid tbr
a particular
application,
101.)171 In some embodiments, the treatment _fluid may further comprise an
aqueous fluid. For example, the tar stabilizing polymer may be dispersed in
the aqueous
fluid to form the treatment fluid. In one embodiment, a latex emulsion
comprising a tar
stabilizing, polymer may be dispersed in the aqueous fluid. In another
embodiment, a
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powder comprising a tar stabilizing polymer may be dispersed in the aqueous
fluid. The
aqueous fluid utilized in .the treatment fluids of the present invention may
be fresh water,
distilled water, or salt water (e.g., water containing, one or more salts
dissolved therein). In
certain embodiments, the treatment fluid may be an aqueous-based fluid.
Generally, the
water can be from any source, provided that it does not contain compounds that
undesirably
affect other components of the treatment fluid,
[00181 In certain embodiments, the treatment fluids of the present invention
may further comprise a viscosifier, for example, to aid in suspending the tar
stabilizing
polymer in the treatment fluid. Suitable viscosifying agents may include, but
are not limited
to, colloidal agents (e.g,, clays such as bentonite, polymers, and guar gum),
emulsion-
forming agents, diatomaceous earth, biopolymers, synthetic polymers,
chitosans, starches,
oektins or mixtures thereof
10019I Other additives suitable for use in subterranean treatment fluids may
also be added to embodiments of the treatment fluids. The treatment fluids of
the present
invention may comprise any such additional additives that do not undesirably
interact with
the tar stabilizing polymer or other components of the fluid. The treatment
fluids used in
methods of the present invention optionally may comprise any number of
additional
additives, including, but not limited to, salts, surfactants, fluid-loss-
control additives, gases
(e.g., nitrogen, carbon dioxide) surface-modifying agents, tack4ing agents,
tbam.ers,
corrosion inhibitors, scale inhibitors, catalysts, clay-control agents,
biocides, friction
reducers, antifoam agents, bridging agents, dispersants. flocculants, hydrogen
,c.ailtide
scavengers, carbon dioxide scavengers, oxygen scavengers, lubricants,
breakers, weighting
agents (e.g., barite), relative-permeability modifiers, resins, particulate
materials (e.g.,
proppant particulates), wetting agents, coating-enhancement agents, and the
like. Weighting
agents may be used, tbr example, in treatment fluids, such as, drilling fluids
to provide a
density sufficient to, for example, control formation pressures. One of
ordinary skill in the
art. with the benefit of this disclosure, will be able to determine which
additional additives
are appropriate for a particular application.
[00201 As will be appreciated by those of ordinary skill in the art, with the
SO benefit of this disclosure, embodiments of the treatment fluids may be
used in a variety of
subterranean operations for treatment of tar resident in a well bore. By
treatment of the tar
with a tar stabilizing polymer, as described herein, the adhesiveness of the
tar may be
reduced, thus facilitating removal of the tar from a well bore or other
surtace, for example.
ID some embodiments, the present invention discloses a method comprising
contacting tar
resident in a well bore with a tar stabilizing polymer, and allowing the tar
stabilizing
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polymer to interact with the tar to at least partially reduce the tendency of
the tar to adhere to
a surface, In this manner, the removal of the tar from the well bore or other
surface may be
facilitated. In one embodiment, a treatment fluid comprising the tar
stabilizing polymer may
be introduced into the well bore such that the tar stabilizing polymer
contacts the tar. One of
ordinary skill in the art, with the benefit of this disclosure, should be able
to determine the
appropriate amount of time to allow the tar stabilizing polymer to interact
with the tar so as
to at least partially reduce the adhesiveness of the tar. In certain
embodiments, after the tar
stabilizing polymer has been allowed to interact with the tar, the tar then
may be removed
from the well bore by any means practicable for the given application.
100211 In some embodiments, a treatment = fluid comprising a tar stabilizing
polymer may be introduced into a well bore as a drilling fluid. For example, a
drill bit may
be used to enlarge the well bore, and the treatment fluid comprising the tar -
stabilizing
polymer may be circulated in the well bore past the drill bit. In some-
embodiments, the
drilling fluid may be passed down through the inside of a drill string,
exiting at a distal end
thereof (e.g., -through the drill bit), and returned to the surface through an
annulus between
the drill string and a well bore wall. Among other things the circulating
drilling fluid should
lubricate the drill bit, carry drill cuttings to the surface, and/or balance
formation pressure
exerted on the well bore. In certain embodiments, the drilling fluid may have
a density in the
range of from about 7,5 pounds per gallon ("tbigal") to about 18 lb/gal, and
alternatively
from about 12 lb/gal to about 18 lb/gal.
[00221 In some embodiments, tar may be encountered in the course of
drilling the well bore. The zones of the well bore may be intentionally or
unintentionally
contacted during the course of drilling. For example, embodiments may include
drilling
through zones of the well bore that contain tar sands. The term "tar sands"
does not imply or
require any specific amount of tar to be present. In some embodiments., one or
more
generally horizontal well bores may be drilled through the tar sands. In
accordance with
present embodiments, a tar stabilizing polymer may be included in the drilling
fluid as the
well bore is drilled in these tar-containing zones. In this manner, the tar
stabilizing polymer
contained in the treatment fluid may modify at least a portion of tar such
that is becomes less
tacky, making it less likely to stick to drill strings and other tubulars used
in drilling
operations. Tar modified in this way may yield tar cuttings that can be
removed more
effectively from the well bore. Additionally, tar that, is drilled through may
be less likely to
flow into the well bore or the subterranean torrnation as the plastic
properties of the tar Duty
be altered. Similarly, the treated tar that forms about the surface of the
well bore may act to
stabilize the well bore. hi addition, tar treated with the tar stabilizing
polymers may be
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separated from a treatment. fluid, by passing the fluid through a screen or
similar separation
apparatus.
100231 In some embodiments, a. treatment fluid comprising a tar stabilizing
pol,yiner may be introduced into a well bore as a. pill for spot treatment,
wherein the
treatment fluid is introduced into the well bore to interact with tar in a
specific portion of the
well bore. In sonic embodiments, the pill may be introduced into a zone of the
well bore that
contains tar sands. The pill should enter the well bore and interact with tar
resident in the
well bore, thus modifying at least a portion of the tar such that is become
less tacky. In
certain embodiments of this type, the tar stabilizing polymer may be allowed
to interact with
the tar resident in the well bore fbr at least .a time sufficient to at least
partially reduce the
adhesiveness of the tar. In some embodiments, this may be more than about one
hour. In
others. more time will be required to at least partially reduce the
adhesiveness of the tar,
dependine. upon, among other factors, the temperature inside the well bore and
the amount of
tar in the portion of the well bore being treated. One of ordinary skill in
the art. with the
benefit of this disclosure, will be able to determine the appropriate amount
of time to allow
the tar stabilizing polymer to interact with the tar. In certain embodiments.
after the tar
stabilizing polymer has been allowed to interact with the tar, the tar then
may be removed
from the well bore by any means practicable for the given application. In
some
embodiments, the pill may he used ahead of and/or behind a non-aqueous
drilling fluid,
which may comprise any number of organic. liquids, including, but are not
limited to, mineral
oils, synthetic oils, esters, paraffin oils, diesel oil, and the like.
[00241 In some embodiments, the amount of the tar stabilizing polymer
present in the treatment fluid may be monitored while the tar stabilizing
polymer is
circulated in the Well bore. For example, Once a unit of tar stabilizing
polymer in a treatment
fluid is allowed to interact with a unit of tar in a well bore, that unit of
the tar stabilizing
polymer may be depleted from the treatment fluid and thus unable to interact
with additional
tar. For this reason, it may be desirable to monitor the concentration of the
tar stabilizing
polymer in the treatment fluid to determine if more should be added. in some
embodiments,
the tar stabilizing polymer may be added to the treatment fluid belbre the
treatment fluid is
introduced into the well bore, for example, a batch-mixing process. in some el-
MN-hint-tents. it
may be desirable to continue to add the tar stabilizing polymer to the
treatment fluid (e.g.,
"on-the-ilv" mixing) according to the monitored concentration of the tar
stabilizing polymer
in the treatment fluid, in some embodiments, the concentration of tar
stabilizing polymer in
the treatment fluid may be monitored by direct measurement. in some
cmbodiments, the
coneentrat ion Of tat stabilizing polymer in the treatment fluid may be
monitored indirectly by
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measuring the depletion of the tar stabilizing polymer from the treatment
fluid. The
concentration of the tar stabilizing polymer in the treatment 'fluid may be
monitored, for
example, by analytical polymer spectroscopy, chromatography, grayimetry, and
quantitative
irecipitation.
100251 To facilitate a better understanding of the present invention. the
1bllowing examples of specific embodiments are Oven. In no way should the
following
examples be read to limit or define the entire scope of the invention.
EXAMPLE .1
[0026] An aqueous-base fluid was formulated as shown in Table I.
Table 1: Base Fluid 1
. .
Fresh Water (lb:4)bl) -345,8
Xanthan Gum (111,/bbl) 0.701
Starch (Ibibbt) 4.206
Cellulose (Ibibbl) 0.701
Caustic Soda (lb/bbl) 0.05
[0027] A nonaqueous-base fluid was also formulated as shown in Table 2,
Table 2: Base Fluid 2
Synthetic Base Oil (Ibibbl) I31,45
Fatty Acid Emulsifier (1b4)b1) 10
Freshwater (lb/bbl) 84.12
Lime (lb/bbl)
'Polymeric Filtration Agent tibibbl)
Barium Sul/ate (1h/bbl) 188.96
Calcium Carbonate (Ibibbl) 15
Calcium Chloride (lb/bbl) 29.09
Simulated Drill Solids (lb/bbl) 20
Rheolotry Modifier (11)./bbl)
[00:28] A 50 g sample of tar sand (25% tar by mass) was placed in a first
1/2 lab barrel along with 133.1 g of Base Fluid I and 3 steel test rod, A 12.5
sample of tar
was placed in a second 1/2 lab barrel along with 216.9 g of Base Fluid 2 and 3
steel test rod,
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The barrels were then hot rolled for 16 hours at 150 'F (approx. 66.7 "C)
under 200 psi in a
rolling cell, and the test rods were visually inspected. .for tar accretion.
Base Fluid I was
contaminated with tar sand, and tar was accreted on the test rod. Base Fluid 2
was
contaminated with tar, and tar was accreted on the test rod.
EXAMPLE 2
[00291 The two fluid samples were prepared as set forth in Table 3 using
Base Fluid I described in Table The fluid samples are designated Sample A
and B in the
table below. The styrene-acrylate polymers used in this example were obtained
as an
emulsion and used as received. Baracor 700"4 corrosion inhibitor is an anti-
corrosion
additive commercially available from flallibUrton Energy Services, flouston,
Texas. After
hot rolling for l 6 hours at 150 'F (approx. 66.7 "C) under 200 psi in a
rolling cell, the mass
of the test rod was determined both with arty accreted tar and after the
accreted tar had been
cleaned off. These .masses and the mass of the accreted tar for each sample is
reported in
'fable 3.
Table 3
Sample A 13
Base Fluid 1 (g) 133.1 150,6
Styrene-Acrylate Emulsion(g) 15 15
Baracor 700rm (Torrosion 0.75 0.75
Inhibitor (m1)
Tar Sand (g) 50
'far (g) 12.5
Post Accretion Test Rod Mass 337.45 337.16
(g)
Post Cleaning Test Rod Mass (g) 337.25 336,93
Mass of accreted tar (g) 0.20 0.23
Tar not sticking to cell wall. Tar form small flocs. Tar
Rod is dean. Tar is firm, not on cell wall. Rod has
not sticky. Sand is separated loosely adhered floes that
Observations
from tar and settled an can be easily brushed
bottom of cell. Fluid not. away. Tar is pliable but
contaminated, not sticky.
EXAMPLE 3
100301 in this example, tar was screened from tar-containing fluids. Base
fluid I was combined with tar sand and, in two cases, a treatment additive. as
illustrated in
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Table 4 below. The tar-containing fluids were hot rolled then poured across a
vibrating
screen material to assess potential screen clogging properties. A screen may
be considered
fouled if the tar is adhesive and begins to seal/clog the screen openings
thereby preventing a
fluid from e(lectively draining. Sample C was a baseline reference of
nontreated, adhesive
tar and yielded adhesive screen fouling, Sample D was an unsuccessful
treatment witti
sodium salt that also yielded adhesive screen tbuling. Sample E was a chemical
treatment of
tar with styrene-acrylate polymers that yielded a non-adhesive tar and
minimized screen
fouling. The styrene-acrylate polymers used in this example (F.) were the same
as in the
previous tests.
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Table 4
Sample
Base Fluid 1(g) 149.8 149,8 149,8
Sodium Salt (g) 26.25
S ne a c ry 1 a te
emulsion(g)
=
Baracor 700'''. Corrosion 0.75
inhibitor (m1)
'Far Sand (a) 50 50 50
EXAMPLE 4
[0031] In this example, another aqueous-base fluid was formulated as
shown in Table 5. This aqueous-base fluid is referred to in Table 5 as Base
Fluid 3,
Table 5; Base Fluid 3
Fresh Water (HA) 0.976
I (341.8 ml)
Xanthan (ium t lb) 0.877
....
Starch Oh) 5-261
Caustic Soda (lb) 0.035
BridOng Agent (Ib)
8,768
Simulated Drill Solids (1b) 1.754
1100321 Fluid samples were prepared by adding a styrene copolymer to Base
Fluid 3 in different quantities to determine its effect on well bore tar, as
set forth in Table 6
below. The fluid samples are designated Samples F and ci in the table below.
The styrene
copolymer was obtained as a latex emulsion (approx. 45 wt c.14) active) and
used as received.
Baracor 700" corrosion inhibitor. available from flalliburton Energy Services,
Inc., was also
added to the fluid samples, as indicated in the table below. Tar sands with
approximately
80% sands and 20% bitumen by weight were used for this test. A steel rod was
used to
mimic the drill strings interaction with the tar sands. For each test, the tar
sands were placed
in a lab barrel together with the respective fluid sample and the steel rod.
The system was
then ailed by rolling at approximately 77 F approx. .25 *C) for 16 hours in a
rolling cell.
The mass of the steel rod was determined prior to testino, without any
accreted tar and after
testing with accreted tar. The mass of the rod was also measured after rinsing
under a stream
1$
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of water. These masses and the mass of the accreted tar for each sample are
reported in the
table below.
Table 6
Sample F (3
Base Fluid 3 (m1) 120 1_20
Styrene Latex Emulsion 10 30
(lb/bbl)
Baracor 700(m Corrosion 6 6
Inhibitor (11)/bbi)
Tar Sands Ilbibbl) 85 85
Pre-Accretion Test Rod Mass 338,53 340.40
(g)
341,75 343,42
Post-Accretion Rod -Mass (10
(338.61 ..ifter rinsing) (341,47
after rinsinil)
'
3.11 3,02
Mass of accreted tar (g) (0.08 after rinsing) (1.07 after rinsing)
Some tar stuck to bar but Sonic tar stuck to bar but
came off very easily under a almost all came off very
slow stream of water. Tar was easily under a slow stream
only very slightly sticky, but of water; however, not all.
not as had as untreated tar. Tar was stuck to the inside
Observations Fluid was not contaminated, of the cell, but it
also came
Tar was far less adhesive and off under a stream of
easily disposed of water. Fluid was not
contaminated. Tar was far
less adhesive and easily
disposed of.
[00331 As set forth in the table above, the tar sands were treated with the
styrene copolymer with the tar becoming non-adhesive in nature. Some of the
tar was
loosely adhered to the steel rod but was only mechanically pressed to the rod
as it slid oil
very easily upon application ola stream of water, revealing the tar's non-
adhesive nature.
EXAMPLE 5
[00341 In this example, two additional fluid samples were prepared by
adding an acrylate copolymer to Base Fluid 3 in different_ quantities to
determine its eftect on
well bore tar, as set forth in Table 7. 'file fluid samples are designated
Samples 11 and I in
the table below. The acrylate copolymer was obtained as a latex emulsion
(approx. 45 wt
active) and used as received. Baracor 700 corrosion inhibitor, available from
Halliburton
Energy Services, Inc., was also added to the fluid samples. as indicated in
the table below.
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Tar sands with approximately 80% sands and 20% bitumen by weight were used for
this test.
A steel rod was used to niume the drill strings interaction with the tar
sands. For each test,
the tar sands were placed in a lab barrel together with the respective fluid
sample and the
steel rod. 'file system was then aged by rolling at approximately. 77 'IF
(approx. 25 C.) for
16 hours in a rollin2, cell. The mass of the steel rod was determined prior to
testing without
any accreted tar and after testing with accreted tar. The mass of the rod was
also measured
after rinsing under a stream of water. These masses and the mass of the
accreted tar for each
sample are reported in the table below.
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Table 7
Sample
Base Fluid 3 (m1) 120 120
------------------------------------- - -----------------
Styrene Latex Emulsion 10 30
(Ibibbl)
Baracor 700s4 (..orrosion 6 6
Inhibitor (Ibibbl)
Tar Sands (1.b/bbl) 85 85
Pre-Accretion Test Rod Mass 335.07
334,6(1
336_40 343.42
Post-Accretion Rod Mass (g)
(335.07 after rinsing)
(334.80 after rinsing)
8,82
Mass of accreted tar (g)
(0.0 after1.33 rinsing)
t0.20 after rinsing)
Some tar was mechanically Tar was mechanically
pressed to the bar but came off pressed to bar but came off
extremely easily under a slow extremely easily under a
stream of water. Tar was not slow stream of water. Tar
Observations
sticky. Tar was also .found was only slightly sticky,
sunken in the -fluid that was but far less so than
not sticky at all. Fluid was not untreated samples. Fluid
contaminated,
was not contaminated.
[0035] 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
or "consist or' the various components and
steps, Whenever a numerical range with a lower limit and an upper limit is
disclosed, any
number and any included range falling within the range are specifically
disclosed. In
particular, ever y range of values of the. form, "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_ 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. Also,
the terms in the
claims have their plain, ordinary meaning unless otherwise explicitly and
clearly defined by
the patentee.
[00361 'therefore, the present invention is well adapted to attain the ends
and
1.5 advantages mentioned as well as those that are inherent therein. "I 'he
particular embodiments
disclosed above are illustrative only, as the present invention may be
modified and practiced
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in different but equivalent manners apparent to those skilled in the art
baying the benefit of
the teachings herein. Although individual embodiments are discussed, the
invention covers
all combinations of all those embodiments. Furthermore, no limitations are
intended to the
details of construction or design herein shown, other .than as described in
the claims below.
It is therefore evident that the particular illustrative embodiments disclosed
above may be
altered or modified and all such variations are considered within the. scope
and spirit of the
present invention.
17
