Note: Descriptions are shown in the official language in which they were submitted.
CA 02641479 2008-10-22
METHOD OF USING POLYQUATERNIUMS IN WELL TREATMENTS
SPECIFICATION
Field of the Invention
The invention relates to the field of fracturing a subterranean formation by
use of
an aqueous fluid, which may be foamed, which contains a polyacrylate friction
reducer.
Background of the Invention
Hydraulic fracturing is a common stimulation technique used to enhance
production of fluids from subterranean formations in oil, gas and geothermal
wells. In a
typical hydraulic fracturing treatment operation, a viscosified fracturing
fluid is pumped
at high pressures and high rates into a wellbore penetrating a subterranean
formation to
initiate and propagate a hydraulic fracture in the formation. Subsequent
stages of
viscosified fracturing fluid containing proppant are then typically pumped
into the
created fracture. Once the treatment is completed, the fracture closes onto a
permeable
proppant pack which maintains the fracture open and provides a highly
conductive
pathway for hydrocarbons and/or other formation fluids to flow into the
wellbore.
Hydraulic fracturing is often used to stimulate low permeability formations
where
recovery efficiency is limited. For instance, hydraulic fracturing may be used
in low
permeability gas reservoirs, such as those having an in-situ matrix
permeability to gas of
0.5 mD or less. Reservoirs with low in-situ matrix permeability often contain
trapped
saturated fluids since the reservoir is in contact with mobile water and
exhibits capillary
equilibrium with the mobile water. Such reservoirs are prevalent in the Deep
Basin area
in Canada, the Powder River Basin in the central portion of the United States
and the
Permian Basin in Texas where the average in-situ permeability may be 0.1mD or
less.
The productivity of low permeability gas reservoirs is dependent on the proper
selection
of an appropriate fracturing fluid.
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Fracturing fluids, especially those used in the stimulation of gas wells,
often
contain an alcohol, such as aqueous methanol, either by itself or in
conjunction with a
foaming agent (surfactant) and a gas, such as carbon dioxide or nitrogen. The
use of an
alcohol in stimulation fluids is desirable for several reasons. First, such
solvents function
as a freezing point depressant and often eliminate the need to heat aqueous
fluids in cold
weather climates. Second, such solvents minimize the tendency of clay in the
reservoir to
swell and migrate. As such, dislodgement of fines and migration of fines into
the
formation or fracture is minimized. Third, the presence of an alcohol prevents
the suction
of connate water into the hydrophilic clays and thus controls water
imbibition, thereby
reducing sub-irreducible initial water saturation within the formation. Such
phenomena
are discussed in Bennion et al, "Low Permeability Gas Reservoirs and Formation
Damage ¨ Tricks and Traps", SPE 59753 (2000).
The stimulation of tight gas reservoirs normally uses aqueous fracturing
fluids
(such as water, salt brine and slickwater) which do not contain viscosifying
polymers.
Slickwater fracturing refers to stimulation of a well by pumping water at high
rates into
the well, thereby creating a fracture in the productive formation. Slickwater
fracturing is
generally cheaper than conventional fracturing treatments which rely upon
fracturing
fluids containing a viscosifying polymer and/or gelled or gellable surfactant.
In addition,
such fluids introduce less damage into the formation in light of the absence
of a
viscosifying polymer and/or surfactant in the fluid.
When aqueous fluids not containing a viscosfiying polymer are used in
stimulation, the pressure during the pumping stage is normally lower than that
required in
fracturing treatments using viscosifying polymers. Such lower pressure is
needed in
order to reduce the frictional drag of the aqueous fluid against the well
tubulars.
Polyacrylamide polymers are widely used as friction reducers for this purpose.
Polyacrylamide emulsions, however, are typically unacceptable, for use in the
treatment of low permeability reservoirs, especially those found in cold
climates. For
instance, polyacrylamides typically precipitate from aqueous emulsions in the
presence of
an alcohol. Further, such fluids typically exhibit poor leakoff control of
filtrate into the
formation in light of their unviscosified nature.
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A need exists therefore for aqueous based fracturing fluids, such as
slickwater
fracturing fluids, which are acceptable for use in low permeability
reservoirs, especially
in reservoirs which are exposed to cold climates.
Summary of the Invention
Hydraulic fracturing using aqueous fracturing fluids is enhanced by the use of
a
well treatment fluid which is void of a viscosifying polymer. The fluid
contains, as a
friction reducer, a high molecular weight polyacrylate of the formula:
(A)a(B)b(C)c,
wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium
or acid
addition salt, B is a dialkylaminoalkyl methacrylate monomer or its quaternary
ammonium or acid addition salt, C is a monomer that is polymerizable with A or
B, a as
an integer of 0 or greater, b is an integer of 0 or greater, c is an integer
greater than 0 and
either a or b, or both, must be 1 or greater.
The alkyl portions of the A and B monomers are preferably C1- C8 alkyl groups.
At least one of A and B is preferably quaternized. Acrylamide is especially
desirable as
the C monomer. In a preferred embodiment, the high molecular polyacrylate is
polyquaternium 32.
In addition, the fluid for use in the invention contains water and an alcohol,
such
as a C1-C4 alkanol.
The method described herein using the well treatment fluid reduces leak-off
from
natural and created fractures into the pores of the formation. The well
treatment fluids
are particularly desirable in the stimulation of tight gas reservoirs where
slickwater
fracturing is desired.
The well treatment fluid may further be used in the cleaning of a wellbore.
For
instance, the well treatment fluid may be used as a cleanout fluid in
conjunction with a
coiled tubing assembly.
The well treatment fluids described herein typically provide greater than 50%
more friction reduction compared to similar well treatment fluids which do not
contain
the high molecular polyacrylate.
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Brief Description of the Drawings
In order to more fully understand the drawings referred to in the detailed
description of the present invention, a brief description of each drawing is
presented, in
which:
FIG. 1 exemplifies the percent friction reduction at 80 F of compositions, pre-
mixed, containing the copolymer friction reducer as defined herein;
FIG. 2 exemplifies the percent friction reduction at 80 F of compositions,
mixed
on the fly, containing the copolymer friction reducer as defined herein; and
FIG. 3 exemplifies the percent friction reduction at 50 F of compositions,
mixed
on the fly, containing the copolymer friction reducer as defined herein;
Detailed Description of the Preferred Embodiments
The well treatment fluid for use in the invention contains a high molecular
weight
polyacrylate of the formula: (A)a(B)b(C)c, wherein A is a dialkylaminoalkyl
acrylate
monomer or its quaternary ammonium or acid addition salt, B is a
dialkylaminoalkyl
methacrylate monomer or its quaternary ammonium or acid addition salt, C is a
monomer
that is polymerizable with A or B (for example a monomer having a carbon-
carbon
double bond or such other polymerizable functional group), a as an integer of
0 or
greater, b is an integer of 0 or greater, c is an integer greater than 0 and
either a or b, or
both, must be 1 or greater.
Suitable monomers of C include ethylene, propylene, butylene, isobutylene,
eicosene, maleic anhydride, acrylamide, methacrylamide, maleic acid, acrolein,
cyclohexene, ethyl vinyl ether, and methyl vinyl ether. In a preferred
embodiment, C is
acrylamide.
The alkyl portions of the A and B monomers are short chain length alkyls such
as
C1- C8, preferably Ci-05, more preferably C1-C3, and most preferably Ci-C2. At
least one
of A and B is preferably quaternized, preferably with short chain alkyls,
i.e., CI- C83
preferably Ci-05, more preferably C1-C3, and most preferably C1-C2. The acid
addition
salts refer to polymers having protonated amino groups. Acid addition salts
can be
obtained through the use of halogen (e.g. chloride), acetic, phosphoric,
nitric, citric, or
other acids.
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The molar proportion of C monomer, based on the total molar amount of A, B and
C, can be from 1 molar % to about 99 molar %. The molar proportions of A and B
can
each be from 0% to 100%. When acrylamide, is used as the C monomer, it will
preferably be used at a level of from about 20% to about 99%, more preferably
from
about 50% to about 90%.
Where monomer A and B are both present, the ratio of monomer A to monomer B
in the final polymer, on a molar basis, is preferably from about 99:5 to about
15:85, more
preferably from about 80:20 to about 20:80. Alternatively, in another class of
polymers,
the ratio is from about 5:95 to about 50:50, preferably from about 5:95 to
about 25:75. In
another alternative class of polymers, the ratio A:B is from about 50:50 to
about 85:15.
Preferably the ratio A:B is about 60:40 to about 85:15, most preferably about
75:25 to
about 85:15.
Most preferred is a cationic polymer where monomer A is not present, B is
preferably methyl quaternized dimethylaminoethyl methacrylate and the ratio of
monomer B:C is from about 30:70 to about 70:30, preferably from about 40:60 to
about
60:40 and most preferably from about 45:55 to about 55:45. An example of a
cationic
polymer is designated as CAS Registry Number 35429-19-7 and may be referred to
as
polyquaternium 32.
In addition, the fluid for use in the invention contains water and an alcohol,
such
as a C1-C4 alkanol. Preferred CI-Ca alkanols are preferably methanol, ethanol
or
isopropanol, most preferably methanol. Further, the water can be any aqueous
solution
such as distilled water, fresh water or salt water or brine. Typically, the
alkanol/water
blend contains between from about 15 to about 80 volume percent of alkanol and
the
remainder water. The well treatment fluid typically contains from about 15 to
about 50
volume percent of the aqueous blend of alkanol and water. Since the fluid
contains a
high percentage of alcohol, the emulsion is particularly efficacious when used
in gas
wells.
The well treatment fluid normally exhibits a viscosity less than or equal to
10
centipoi se s.
The high molecular weight polyacrylate may be prepared by polymerization of
the monomers in an aqueous solution in the presence of an initiator (usually a
redox or
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CA 02641479 2008-10-22
=
thermal initiator) until the polymerization terminates. In the polymerization
reaction, the
temperature generally starts between about 0 C and 95 C.
In a preferred embodiment, the polymerization is conducted by forming an
invert
(or reverse) emulsion of an aqueous phase of the monomers in an outer (or
continuous)
hydrophobic phase of non-aqueous solvent which is either non-miscible in or
slightly
miscible with water. Suitable non-aqueous solvents include as mineral oil,
lanolin,
isododecane, oleyl alcohol and other volatile and other nonvolatile solvents
like terpenes,
mono-, di- and tri-glycerides of saturated or unsaturated fatty acids
including natural and
synthetic triglycerides, aliphatic esters such as methyl esters of a mixture
of acetic,
succinic and glutaric acids, aliphatic ethers of glycols such as ethylene
glycol monobutyl
ether, minerals oils such as vaseline oil, chlorinated solvents like 1,1,1-
trichloroethane,
perchloroethylene and methylene chloride, deodorized kerosene, solvent
naphtha,
paraffins (including linear paraffins), isoparaffins, olefins (especially
linear olefins) and
aliphatic or aromatic hydrocarbons (such as toluene).
Such reverse emulsions release the high molecular weight polyacrylate upon
contact with the aqueous mixture of water and alcohol where the polyacrylate
hydrates.
Thus, they are particularly useful when used on the fly since inversion may
occur almost
immediately when placed into contact with water. Such reverse emulsions are
particularly
desirable when slickwater is used. Inversion of the emulsion typically occurs
almost
instantaneously even at a temperature of 50 F.
The outer phase may further contain a surfactant which enhances the formation
of
the emulsion and facilitates the inversion of the emulsion into the aqueous
mixture. The
surfactant is preferably hydrophobic though it may be characterized as having
portions
which are strongly attracted to each of the phases present, i.e., hydrophilic
and
hydrophobic portions. Suitable surfactants include non-ionic as well as ionic
surfactants
such as sorbitan derivatives, glycerol derivatives, cetyl alcohol derivatives,
polyoxyalkylenes and sulfonates. Particular surfactants may include sorbitan
trioleate and
polyoxyethylenated sorbitans, glycerol monostearate, propylene glycerol
monostearate,
sodium cetyl stearyl sulfate, cetyl ethyl morpholinium ethosulfate,
polyoxyethylene alkyl
amines and alkyl aryl sulfonates.
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A particularly preferred polyacrylate-containing reverse emulsion for use in
the
invention is one which is an approximate 50% by weight dispersion of 1 micron
diameter
particles with low water content (<6%) and contains essentially linear high
molecular
weight cationic acrylamide copolymer in a naphthenic mineral seal oil. The
copolymer
may consist of 20% by weight acrylamide and about 80% by weight of
methacryloxyethyl trimethyl ammonium chloride and has a molecular weight
between
about 5 to 7 million. Such products may be commercially available as a mineral
oil
dispersion from Ciba Specialty Chemicals PLC under the trademark ZETAGo.
The well treatment fluid may further be combined with proppant and breaker.
When used, the breaker is typically an oil or is oil-based. Suitable breakers
in such
circumstances include mineral oil.
The well treatment fluids used herein exhibit acceptable fluid loss control
properties and thus reduce leak-off from the fracture into the pores of the
formation. In
addition to preventing leak-off, the fluids exhibit a viscosity which is
sufficient to support
proppant without settling. The fluid, however, is void of a crosslinked or non-
crosslinked
viscosifying polymer (a polymer which imparts viscosity to the fluid).
The well treatment fluid used herein may further be energized (containing less
than or equal to 63 volume percent of foaming agent) or foamed with a gas
(containing
more than 63 volume percent of foaming agent). Any foaming agent may be
employed
though the foaming agent is most preferably nitrogen and/or carbon dioxide.
The
presence of the gas in the well treatment fluid is especially effective in
controlling leak
off into the natural and created fractures as well as providing increased
viscosity to the
fluid while minimizing the amount of water pumped into the formation.
The well treatment fluids described herein typically provide greater than 50%
more friction reduction compared to similar well treatment fluids which do not
contain
the high molecular polyacrylate. The well treatment fluids described herein
further
minimize the tendency of clay in the reservoir to swell and migrate.
The well treatment fluids are particularly desirable in the stimulation of low
permeability gas reservoirs such as when slicicwater fracturing is employed.
The
presence of the polyacrylate in the well treatment fluid reduces the
frictional drag of the
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aqueous fluid against tubulars within the wellbore. Further, use of the well
treatment
agent in slickwater fracturing improves leakoff control of filtrate into the
formation.
The well treatment fluids described herein may further be used as a cleaning
fluid.
For instance, the well treatment fluid may be used to clean unwanted
particulate matter
from a wellbore such as fills which accumulate in the bottom or bottom
portions of oil
and gas wellbores. The fill may include proppant, weighting materials, gun
debris,
accumulated powder as well as crushed sandstone. Fill might include general
formation
debris and well rock in addition to cuttings from drilling muds. The well
treatment fluids
may be used in conjunction with conventional cleaning equipment. More
particularly,
the well treatment fluids may be used in conjunction with coiled tubing. For
instance, the
well treatment fluid may be used to clean fill from a wellbore by disturbing
particulate
solids by running in hole with a coiled tubing assembly while circulating the
fluid
through a nozzle having a jetting action directed downhole. This may include
creating
particulate entrainment by pulling out of hole while circulating the well
treatment fluid
through a nozzle having a jetting action directed uphole. Such mechanisms and
coiled
tubing systems include those set forth in U.S. Pat. No. 6,982,008.
The following examples are illustrative of some of the embodiments of the
present invention.
All percentages set forth in the Examples are given in terms of weight units
except as may otherwise be indicated.
Examples
The Examples illustrate the ability of the subject friction reducer to rapidly
hydrate in a winterized methanol/water solution.
The following components were used in the Examples:
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ZETAG 7888, a 50% by weight dispersion containing a copolymer of
acrylamide 20% and methacryloxyethyl trimethyl ammonium chloride 80% (by
weight)
of molecular weight between from 5 to 7 million, in a naphthenic mineral seal
oil;
ALCOMER 11ORD, a dry polyacrylamide friction reducer;
MAGNAFLOC 156, a high molecular weight fully anionic polyacrylamide
flocculant, supplied as a free flowing micro bead.
FRW-14, a high molecular weight acrylamidomethylpropane sulfonic acid
(AMPS) copolymer friction reducer formulation, a product of BJ Services
Company; and
ALCOMER 11ORD, a high molecular weight, anionic, water-soluble,
acrylamide-based copolymer, supplied as a free-flowing powder.
Examples 1-11. These Examples relate to the solubility of the tested
components.
Approximately 60 ml of tap water was measured into a glass beaker. While
stirring using
an overhead stirrer, 40 ml of methanol was added. The methanol/water solution
was
mixed for about a minute, and then polymer was added. The fluid was mixed for
another
15 minutes at 2500 rpm. Compositions and results are set forth in Table I
below:
Table I
Ex. No. Water, Methanol, Polymer, Amount Observations
ml ml
Comp. 60 40 ALCOMER 11ORD, 0.012 Polymer swelled, not
completely in solution.
Ex. I vol. %
Comp. 80 20 ALCOMER 11ORD, 0.012 Polymer swelled, not
completely in solution.
Ex. 2 vol. %)
Comp Ex. 60 40 ALCOMER 11ORD, 0.25 Polymer swelled and sample
gelled, not
3 vol %) completely in solution
Comp. 60 40 FRW-14, 0.5 gpt Settling on bottom of glass
jar, not into
Ex. 4 solution.
Comp. 80 20 FRW-14, 0.5 gpt Went into solution only after
mixing of
Ex. 5 polymer.
Comp. 70 30 FRW-14, 0.5 gpt Went into solution only after
mixing of
Ex. 6 polymer.
7 60 40 ZETAG 7888, 0.5 gpt Very thick gel, polymer
went into solution.
8 60 40 ZETAG 7888, 1 gpt Sample gelled, polymer
into solution.
9 60 40 MAGNAFLOC 156, 1 ppt Insoluble.
10 70 30 MAGNAFLOC 156, 1 ppt Sample did not gel;
polymer into solution
only after mixing.
11 80 20 MAGNAFLOC 156, 1 ppt Sample did not gel,
polymer into solution
only after mixing.
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As set forth in Table I, the polymer in Comparative Examples 1-3 did not
hydrate in the
water/methanol solutions. ALCOMER 11ORD needs high shear (8000 rpm) and water
with no methanol to go into solution. In Comparative Example 4, the polymer
precipitated when added to a 60/40 water/methanol solution. In Comparative
Examples
5-6, the polymer went into solution only at lower methanol concentration
solutions with
additional mixing. In Examples 7-8, the polymer was soluble in a 60/40
water/methanol
solution at both concentrations, 0.5 gpt and 1 gpt. In Comparative Examples 9-
11, the
polymer at 1 ppt was soluble in solutions with lower methanol concentration
solutions
(70/30 water/Me0H and lower). The product further required at least 15 minutes
of
mixing time.
Examples 12-17.
The amount of friction reduction of various friction reducers in
methanol/water
solutions was determined.
A friction loop was comprised of a small gear pump with a range of 1.5-3.25
gpm, a manual pressure gauge, and 20 ft. of 1/4" tube coiled in a circle of
1.5 ft. diameter.
Fluid was drawn from a bucket into the pump via a large 1/4" nylon tube. The
fluid passed
through the pump. Immediately after exiting the pump, the fluid passed through
the
pressure transducer, situated between the pump and the section of tubing.
After passing
through the 1/4" stainless steel tubing, the fluid entered a short section of
3/4" nylon tubing
that was submerged in the fluid as it re-entered the bucket. This prevented
air entrapment
in the fluid. Fluid was re-circulated through the coil continuously at various
flow rates.
Tap water (1800 ml), methanol (1200 ml) and polymer were mixed in high shear
with an overhead stirrer for 15 minutes. Fluid was transferred to the friction
loop bucket
and a screening loop program was allowed to commence. The fluid was circulated
through the loop initially at the highest flow rate and then decreasing flow
rate in several
increments. Differential pressure was measured at each flow rate.
The compositions tested are set forth in Table II:
CA 02641479 2008-10-22
Table II
Ex. No. Polymer, Amount
Comp. Ex. 12 ALCOMER 1101W, 1.0 ppt
_ Comp. Ex. 13 ALCOMER 11ORD, 5.0 ppt
Ex. 14 ZETAG 7888, 0.25 gpt
Ex. 15 ZETAG 7888, 0.5 gpt
Ex. 16 ZETAG 7888, 1.0 gpt
Ex. 17 ZETAG 7888, 1.5 gpt
FIG. 1 exemplifies the percent friction reduction at 80 F at the stated
concentrations in
the water/methanol solution. As shown in FIG. 1, Example 15 rendered the best
friction
reduction performance Examples 16 and 17 also show significant friction
reduction in
the 60% water and 40% methanol solution. ZETAG 7888 at the 0.25 gpt
concentration
in the 60% water and 40% methanol solution showed some shear degradation with
time
at shear.
Examples 18-21.
The amount of friction reduction of various friction reducers in
methanol/water
solutions was determined by mixing the components on the fly.
The friction loop was comprised of a small gear pump with a range of 1.5-3.25
gpm, a manual pressure gauge, and 20 ft. of 1/4" tube coiled in a circle of
1.5 ft. diameter.
Fluid was drawn from a bucket into the pump via a large 3/4" nylon tube. The
fluid passed
through the pump. Immediately after exiting the pump, the fluid passed through
the
pressure transducer, situated between the pump and the section of tubing.
After passing
through the 1/4" stainless steel tubing, the fluid entered a short section of
3/4" nylon tubing
that was submerged in the fluid as it re-entered the bucket. This prevented
air entrapment
in the fluid. Fluid was re-circulated through the coil continuously at various
flow rates.
To the screening loop bucket were added 1800 ml of water and 1200 ml of
methanol. The polymer and optional surfactant (a hydrate enhancer composed of
alkoxylated alcohols, commercially available as PSA-2L from BJ Services
Company,
were then added to the re-circulating fluid. The fluid was circulated through
the loop,
and the differential pressure was recorded every second for 5 to 10 minutes
total
circulation time. Testing was conducted in ambient temperature conditions, ¨80
F, and
in cold water at 50 F. The compositions tested are set forth in Table III:
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Table III
Ex. No. Polymer, Amount (gpt) PSA-2L, gpt
Ex. 18 ZETAG 7888,0.25 2.0
Ex. 19 _ ZETAG 7888, 0.5
Ex. 20 ZETAG 7888, 0.5 2.0
Ex. 21 ZETAG 7888, 0.5 3.0
FIG. 2 exemplifies the percent friction reduction at 80 F at the stated
concentrations in
the water/methanol solution. As shown in FIG. 2, hydration is much faster and
friction
reduction is quicker when the formulation contains PSA-2L at a concentration
of polymer
of 0.25 gpt. Formulations containing a concentration of polymer of 0.5 gpt
hydrates
quickly and shows excellent friction reduction. FIG. 3 exemplifies the percent
friction
reduction at 50 F at the stated concentrations in the water/methanol solution.
As shown
in FIG. 3, hydration is also much faster and friction reduction is quicker
when the
formulation contains PSA-2L at a concentration of polymer of 0.25 gpt.
Hydration rate
of the polymer at a concentration of 0.5 gpt is slowed by the addition of the
PSA-2L.
Example 22. This Example illustrates the carbon dioxide compatibility of ZETAG
7888. A 500 inL sample fluid was prepared containing 5 gpt ZETAG0 7888 in
60/40
v/v mixture of fresh water and methanol was prepared. About 300 mL of the
fluid was
introduced into a large chamber viewing cell, typically used to inspect foams.
The cell
was oriented vertically and there were two valves on the bottom of the viewing
cell and
one valve and a pressure regulator on the top of the viewing cell. The fluid
was poured
into the viewing cell from the top through a funnel and the existing 1/2"
stainless steel
tubing. This filled the chamber to about 50% of its volumetric capacity. The
top valve
and regulator were then replaced. Carbon dioxide was then flowed from a dip
(siphon)
tube bottle with the flow being regulated by a CO2 pressure regulator. Carbon
dioxide
was then introduced into the bottom of the cell and effectively bubbled up
through the
liquid fluid. The pressure on the chamber was controlled via the regulator on
top of the
viewing cell. Observations were made looking for color changes, precipitates
and solids
or any other indications that would be consistent with fluid incompatibility.
No
incompatibility was noted. The fluid remained cloudy, but no particulates were
noted in
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the view cell or graduated cylinder. The
pressure was then relieved via the top (a
ventilator was used to evacuate the area of any C07). The fluid was drained
out and a
250 mL sample was captured in a glass graduated cylinder, which was placed on
the
counter top and observed for 1 day. No incompatibility was observed.
13
