COMPOSITION AND METHOD FOR
REDUCING HYDRATEAGGLOMERATION
CROSS REFERNCE TO RELATED APPLICATION
This application claims the benefit of U.S. provisional patent application no. 61/426,029,
"Composition and Method for Reducing Hydrate Agglomeration," filed on December 22, 2010,
which is incorporated herein in its entirety by reference.
TECHNICAL FIELD OF THE INVENTION
This invention relates generally to reducing or inhibiting the formation and growth of
hydrate particles in fluids containing hydrocarbon gas and water. More specifically, the
invention relates to reducing or inhibiting such formation in the production and transport of
natural gas, petroleum gas, or other gases. The invention has particular relevance to treating such
systems with beta-amino amide surfactants as anti-agglomerants to reduce or inhibit the
formation of gas hydrates.
BACKGROUNDOF THE INVENTION
Since Hammerschmidt discovered in 1934 that gas hydrates would block gas pipelines,
research for the prevention of hydrate formation and agglomeration has become an important
matter. Gas hydrate4 can be easily formed during the transportation of oil and gas in pipelines
when the appropriate conditions are present. Water content, low temperatures, and elevated
pressure are required for the formation of gas hydrates. The formation of gas hydrates often
result on lost oil production, pipeline damage, and safety hazards to field workers. Modern oil
and gas technologies commonly operate under severe conditions during the course of oil
recovery and production; for instance, high pumping speed, high pressure in the pipelines,
extended length of pipelines, and low temperature of the oil and gas flowing through the
pipelines. These conditions are particularly favorable for the formation of gas hydrates, which
can be particularly hazardous for oil productions offshore or for locations with cold climates.
Gas hydrates are ice-like solids that are formed from small nonpolar molecules and water
at lower temperatures and at increased pressures. Under these conditions, the water molecules
can form cage-like structures around these small nonpolar molecules (typically dissolved gases
such as carbon dioxide, hydrogen sulfide, methane, ethane, propane, butane and iso-butane),
creating a type of host-guest interaction also known as a clathrate or clathrate hydrate. The
specific architecture of this cage structure can be one of several types (called type 1, type 2, type
H), depending on the identity of the guest molecules. However, once formed, these crystalline
cage structures tend to settle out from the solution and accumulate into large solid masses that
can travel by oil and gas transporting pipelines, and potentially block or damage the pipelines
and/or related equipment. The damage resulting from a blockage can be very costly from an
equipment repair standpoint, as well as from the loss of production, and finally the resultant
environmental impact.
The industry uses a number of methods to prevent such blockages such as thermodynamic
hydrate inhibitors (TH1), anti-agglomerants (AA), and kinetic hydrate inhibitors (KH1). The
amount of chemical needed to prevent blockages varies widely depending upon the type of
inhibitor that is employed. Thermodynamic hydrate inhibitors are substances that can reduce the
temperature at which the hydrates form at a given pressure and water content and are typically
used at very high concentrations (regularly dosed as high as 30% based on water content - glycol
is often used in amounts as high as 100% of the weight of the produced water). Therefore, there
is a substantial cost associated with the transportation and storage of large quantities of these
solvents.
A more cost-effective alternative is the use of LDHls, as they generally require less that
2% dose to inhibit the nucleation or growth of gas hydrates. There are two general types of
LDHIs, kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs), which are both typically
used at much lower concentrations (0.3-0.5 % active concentration). KHIs work by delaying the
growth of gas hydrate crystals and as anti-nucleators. AAs allow the hydrates to form but they
prevent them from agglomerating and subsequent accumulation into larger masses capable of
causing plugs. An AA enables gas hydrates to form but in the shape of fluid slurry dispersed in
the liquid hydrocarbon phase. In general, the water cut should be below 50% otherwise the
slurry become too viscous to transport.
There is therefore an ongoing need for new and effective methods of inhibiting the
formation of hydrate agglomerates, particularly those that are capable of operating under higher
water-cuts.
BRIEF SUMMARY OF THE INVENTION
Accordingly, this invention pertains to anti-agglomerant compositions as well as methods
for inhibiting the formation of hydrate agglomerates in an aqueous medium comprising water,
gas, and optionally liquid hydrocarbon.
in (he above formula, R1, R2, and R 3 are each independently CnH2n+1 or benzyl. R4 is C4-
C20 alkyIor alkenyl. n is an integer from 0 to 10. X- is a counterfoil.
In another aspect, the present invention provides for a method of inhibiting the formation
of hydrate agglomerates in an aqueous medium comprising water, gas, and optionally liquid
hydrocarbon comprising adding to the aqueous medium an effective anti-agglomerating amount
of a composition comprising the above formula and optionally salts thereof.
It is an advantage of the invention to provide anti-agglomerant compositions useful for
the prevention of hydrate plugs in oil production pipes.
It is another advantage of the invention to provide anti-agglomerant compositions thai do
not negatively affect the overboard water quality.
It is a further advantage of the invention to provide anti-agglomerant compositions that
are capable to be delivered in subsea umbilical lines.
The foregoing has outlined rather broadly the features and technical advantages of the
present invention in order that the detailed description of the invention that follows may be better
understood. Additional features and advantages of the invention will be described hereinafter
that form the subject of the claims of the invention. It should be appreciated by those skilled in
the art that the conception and the specific embodiments disclosed may be readily utilized as a
basis for modifying or designing other embodiments for carrying out the same purposes of the
present invention. Tt should also be realized by those skilled in the art that such equivalent
embodiments do not depart from the spirit and scope of the invention as set forth in the appended
claims.
DETAILED DESCRIPTION
The compositions of th invention comprise a generic formula and optionally salts thereof
as given below.
In the above formula, R1, R2, and R 3 are each independently CnH2n+1 or benzyl. R4 is C4-
C20 alkyl or alkenyl. n is an integer from 0 to 10. X' is a counterion.
"Alkenyl" means a monovalent group derived from a straight, branched, or cyclic
hydrocarbon containing at least one carbon-carbon double bond by the removal of a single
hydrogen atom from each of two adjacent carbon atoms of an alkyl group. Representative alkenyl
groups include, for example, ethenyl, propenyl, butenyl, l-methyl-2-buten-1-yl, and the like.
"Alkyl" refers to a monovalent group derived by the removal of a single hydrogen atom
from a straight or branched chain or cyclic saturated or unsaturated hydrocarbon. Representative
alkyl groups include methyl, ethyl, propyl, butyl, pentyl, hexyl, heptyl, octyl, nonyl, and decyl.
"Counterion" refers to a halide selected from fluoride, chloride, bromide, iodide, or
carboxylate selected from reaction with mineral acid, acrylic acid, acetic acid, methacrylic acid,
glycolic acid, thioglycolic acid, propionic acid, butyric acid, the like, and any combination
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof. R is at least one or a mixture of saturated or unsaturated C8, C10, C 12 , C14, C16 , and C18.
In embodiments, R is derived from cocoamine.
In an embodiment, the composition comprises the following formula and optionally salts
thereof. R is at least one or a mixture of saturated or unsaturated C8, C10, C 12 , C14, C16 , and C18.
In embodiments, R is derived from cocoamine ("coco").
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
In an embodiment, the compositiom comprises the following formula and optionally salts
thereof.
In an embodiment, the composition comprises the following formula and optionally salts
thereof.
Various synthesis methodologies, which can be appreciated by one of ordinary skill in the
art, can be utilized to make the claimed compositions. Detailed representative synthetic schemes
are provided in the examples.
The compositions of this invention can contain one or more additional chemistries.
Various formulations can be appreciated by one of ordinary skill in the art and can be made
without undue experimentation.
in one embodiment, the composition further comprises at least one additional hydrate
inhibitor. Exemplary hydrate inhibitors are disclosed in U.S. Patent Application Serial Nos.
12/253,504, "Method of Controlling Gas Hydrates in Fluid Systems," tiled October 17, 2008,
12/253,529, "Method of Controlling Gas Hydrates in Fluid Systems," filed October 17, 2008,
12/400,428, "Compositions and Methods for Inhibiting the Agglomeration of Hydrates in a
Process," filed March 9, 2009, 12/967,81 1, "Composition and Method for Reducing Hydrate
Agglomeration," filed December 16, 2008, all currently pending and incorporated herein by
reference.
In an embodiment, the invention comprises the following formula and optionally salts
thereof (including at least monobutyl amine reactions with 2 equivalents of acrylic acid):
In another embodiment, the composition further comprises one or more thermodynamic
hydrate inhibitors, one or more kinetic hydrate inhibitors, one or more anti-agglomerants, or a
combination thereof.
In another embodiment, the composition further comprises one or more asphaltene
inhibitors, paraffin inhibitors, corrosion inhibitors, scale inhibitors, emulsifiers, water clarifiers,
dispersants, emulsion breakers, or a combination thereof.
In another embodiment, the composition further comprises one or more polar or nonpolar
solvents or a mixture thereof.
In another embodiment, the composition further comprises one or more solvents selected
from isopropanol, methanol, ethanol, 2-ethylhexanol, heavy aromatic naphtha, toluene, ethylene
glycol, ethylene glycol monobutyl ether (EGMBE), diethylene glycol monoethyl ether, xylene, or
a combination thereof.
The composition is introduced into the fluid by any means suitable for ensuring dispersal
of the inhibitor through the fluid being treated. Typically the inhibitor is injected using
mechanical equipment such as chemical injection pumps, piping tees, injection fittings, and the
like. The inhibitor mixture can be injected as prepared or formulated in one or more additional
polar or non-polar solvents depending upon the application and requirements.
Representative polar solvents suitable for formulation with the inhibitor composition
include water, brine, seawater, alcohols (including straight chain or branched aliphatic such as
methanol, ethanol, propanol, isopropanol, butanol, 2-ethylhexanol, hexanol, octanol, decanol, 2-
butoxyethanol, etc.), glycols and derivatives (ethylene glycol, 1,2-propylene glycol, 1,3-
propylene glycol, ethylene glycol monobutyl ether, etc.), ketones (cyclohexanone,
diisobutylketone), N-methylpyrrolidinone (NMP), N.N-dimethylformamide and the like.
Representative of non-polar solvents suitable for formulation with the inhibitor
composition include aliphatics such as pentane, hexane, cyclohexane, methylcyclohexane,
heptane, decane, dodecane, diesel, and the like; aromatics such as toluene, xylene, heavy
aromatic naphtha, fatty acid derivatives (acids, esters, amides), and the like.
In embodiments of the invention, the disclosed composition is used in a method of
inhibiting the formation of hydrate agglomerates in an aqueous medium comprising water, gas,
and optionally liquid hydrocarbon. The method comprises adding to the aqueous medium an
effective anti-agglomerant amount of the disclosed composition.
The composition and method of this invention is effective to control gas hydrate
formation and plugging in hydrocarbon production and transportation systems. To ensure
effective inhibition of hydrates, the inhibitor composition should be injected prior to substantial
formation of hydrates. A preferred injection point for petroleum production operations is
downhole near the near the surface controlled sub-sea safely valve. This ensures that during a
shut-in, the product is able to disperse throughout the area where hydrates will occur. Treatment
can also occur at other areas in the flowline, taking into account the density of the injected fluid.
f the injection point is well above the hydrate formation depth, then the hydrate inhibitor should
be formulated with a solvent with a density high enough that the inhibitor will sink in the
flowline to collect at the water/oil interface. Moreover, the treatment can also be used for
pipelines or anywhere in the system where there is a potential for hydrate formation.
In embodiments, the composition is applied to an aqueous medium that contains various
levels of salinity. In one embodiment, the fluid has a salinity of 0% to 25%, about 1% to 24%, or
about 10% to 25% weight/weight (w/w) total dissolved solids (TDS). The aqueous medium in
which the disclosed compositions and/or formulations are applied can be contained in many
different types of apparatuses, especially those that transport an aqueous medium from one point
to another point.
Tn embodiments, the aqueous medium is contained in an oil and gas pipeline. In other
embodiments, the aqueous medium is contained in refineries, such as separation vessels,
dehydration units, gas lines, and pipelines.
In embodiments, the composition is applied to an aqueous medium that contains various
levels of water cut. One of ordinary skill in the art would interpret water cut to mean the % of
water in a composition containing an oil and water mixture. In one embodiment, the water cut is
from 1to 80% w/w total dissolved solids.
The compositions of the present disclosure and/or formulations thereof can be applied to
an aqueous medium in various ways that would be appreciated by of ordinary skill in the art. One
of ordinary skill in the art would appreciate these techniques and the various locations to which
the compositions or chemistries can be applied.
In one embodiment, the compositions and/or formulations are pumped into the oil/gas
pipeline by using an umbilical line. In a further embodiment, capillary string injection systems
can be utilized to deliver the compositions and/or formulations of the invention, in this case antiagglomeranls.
U.S. Patent No. 7,311,144 provides a description of an apparatus and methods
relating to capillary injection.
Various dosage amounts of a composition and/or formulation can be applied to the
aqueous medium to inhibit the formation of hydrate agglomerates. One of ordinary skill in the art
would be able to calculate the amount of anti-agglomerant for a given situation without undue
experimentation. Factors that would be considered of importance in such calculations include, for
example, content of aqueous medium, percentage water cut, API gravity of hydrocarbon, and test
gas composition.
In one embodiment, the dose range for the hydrate inhibitor that is applied to an aqueous
medium is between about 0.1% volume to about 3% volume based on water cut. In another
embodiment, the dose range is from about 0.25% volume to about 1.5% volume based on water
cut.
The methodologies described in the present invention may be utilized with other
compositions that are commensurate in scope with this disclosure. Other chemistries used for
inhibiting the formation of agglomerants in fluids, which are outside the specific generic formula
described above, but arc commensurate in scope with the claimed compositions generic formula,
may be utilized if the system conditions permit the compositions to inhibit the formation of
agglomerants (hydrate agglomerates). This protocol can be achieved without undue
experimentation, specifically, for example, the rocking test described below can be utilized in
determining the effectiveness of a given chemistry.
The foregoing may be better understood by reference to the following examples, which
are intended for illustrative purposes and are not intended to limit the scope of the invention.
Example 1
A representative synthetic scheme is given below for the synthesis of N-butyl-N-(3
(cocoamino)-3-oxopropyl)butan-1-aminium acetate.
To a 250-mL, 3-neck round bottom flask was added 40.00 g (0.3 1 mol) dibutylamine and
a magnetic stirbar. The tlask was fitted with a thermocouple, reflux condenser, and addition
funnel containing 22.30 g (0.31 mol) acrylic acid. The acrylate was added to the stirring amine
slowly. Once the addition was complete, the addition funnel was replaced with a glass stopper
and the reaction mixture was heated at 120 °C for 2 hours. Upon cooling to ambient temperature,
an orange solid was formed. Complete conversion was confirmed by the disappearance of the
dibutylamine starting material by TLC (1/5 CHCl3/MeOH with 0.5% v/v NH*OH). To the orange
solid was added 60.58 g (0.31 mol) cocoaminc. An insulated Dean-Stark trap was attached to the
apparatus between the flask and reflux condenser for water removal. The reaction mixture was
heated at 165 C for 6 hours at which time TLC analysis (8/1 CHCl3/MeOH with 0.5% v/v
NH4OH) confirmed the disappearance of the intermediate carboxylic acid. Upon cooling to
ambient temperature a light orange liquid was formed. To the resulting amide at ambient
temperature was slowly added 18.59 g (0.31 mmol) acetic acid and the reaction mixture was
stirred at ambient temperature for 2 hours.-
Example 2
A representative synthetic scheme is given below for the synthesis of N,N-dibutyl-N-(3-
(cocoamino)-3-oxopropyl)hexan- 1-aminium bromide.
To a 230-mL, 3-neck round bottom flask was added 40.00 g (0.31 mol) dibutylamine and
a magnetic stirbar. The flask was fitted with a thermocouple, reflux condenser, and addition
funnel containing 22.30 g (0.3 1 mol) acrylic acid. The acrylate was added to the stirring amine
slowly. Once the addition was complete, the addition funnel was replaced with a glass stopper
and the reaction mixture was heated at 120 °C for 2 hours. Upon cooling to ambient temperature,
an orange solid was formed. Complete conversion was confirmed by the disappearance of the
dibutylamine starting material by TLC (1/5 CHCl3/MeOH with 0.5% v/v NH4OH). To the orange
solid was added 60.S8 g (0.31 mol) cocoamine. An insulated Dean-Stark trap was attached to the
apparatus between the flask and reflux condenser for water removal. The reaction mixture was
heated at 165 °C for 6 hours at which time TLC analysis (8/1 CHCl3/MeOH with 0.5% v/v
NH4OH) confirmed the disappearance of the intermediate carboxylic acid. Upon cooling to
ambient temperature a light orange liquid was formed. To the resulting amide at ambient
temperature was added 51.09 g (0.31 mol) 1-bromohexane and 42.07 g 2-propanol. The reaction
mixture was heated at 97.5 °C for 6 hours.
Example 3
Samples 1 to 4 of Table 1 are the cationic ammonium products of the reaction of acrylic
or acetic acid with the adduct formed from the addition of commercially available acrylic acid to
dibutylamine followed by amidation with cocoamine. Samples 5 to 10 are the quaternization
products of the reaction of 1-chlorobutane, 1-bromobutane, or 1-bromohexane with the adduct
formed from the addition of commercially available acrylic acid to dibutylamine followed by
amidation with cocoamine. All of the ammonium species are soluble in 2-propanol (1PA),
methanol, ethylene glycol (MEG), ethylene glycol monobutyl ether (EGMBE), glycerol, heavy
aromatic naphtha (HAN) and combinations thereof. Samples 1 to 10 were dissolved to 40% w/w
for the anti-agglomeration test.
The rocking cell test is the primary test for assessing the performance of an antiagglomerant
chemistry. Chemistries are evaluated based on their ability to effectively minimize
the size of hydrate agglomerate particles and then disperse those particles into the hydrocarbon
phase. Chemical performance is evaluated by determining the maximum treatable water cut
(water to oil ratio) and the minimum chemical dosage to register a pass in the rocking cell test.
A rocking cell has two parts, manifold and cell body. The manifold is made of stainless
steel fittings weld together. It has three stems, inlet stem is used to charge gas into the cell.
Outlet stem is used to release the gas out of cell. Third steam is connecting to transducer, which
measures the pressure inside of the cell. Cell body has three layers. The outer layer is a
polycarbonate tube, which thickness is 0.7 cm. The middle layer is made of stainless steel metal,
and been connected to the manifold. The inner layer is high-pressure sapphire tube, which outer
diameter is 2.8 cm, inner diameter is 1.8S cm, and length is S cm. This sapphire tube can handle
up 3000 psi. A stainless steel ball of 1.6 cm of diameter is located inside sapphire tube to induce
turbulence and mix fluids during the rocking process.
Test fluids usually contain three components. For this anti-agglomerant test, a correct
amount of warm Magnolia crude oil is injected into the cell first. Next, a solution of 7% by
weight of NaCl and Dl water was injected with the accurate amount according to the percent of
aqueous phase. Chemical, low dosage hydrate inhibitor, is the final component injected into the
cell. The dosage of chemical is based on the volume of aqueous phase. Test was set at 2 1 °C as
initial condition. Each cell is charged by Green Canyon gas and pressurized up to 2,100 psi. All
cells rock for at least 1.5 to 2 hours until fluid is saturated and pressure stabilizes. Next,
temperature is reduced to the set point of 4°C. Cells rocked for 16 hours, held static for 6 hours,
and rocked back for 2 hours. Pressure data is recorded during this time. Observations are taken
every two to three hours, before stopped rocking and also immediately after the restart.
Table 2. Rocking cell experiment results for new anti-agg!omerant chemistries
The new chemistries provide not only an increase in chemical performance in the rocking
cell lest, but a significant increase in overboard water quality. Surfactant has a tendency to
stabilize emulsion at the oil/water interface. This chemistry has shown in laboratory bottle test
experiments to result in enhanced water quality and found to be more reactive with a number of
water clarificrs.
All of the compositions and methods disclosed and claimed herein can be made and
executed without undue experimentation in light of the present disclosure. While this invention
may be embodied in many different forms, there are described in detail herein specific preferred
embodiments of the invention. The present disclosure is an exemplification of the principles of
the invention and is not intended to limit the invention to the particular embodiments illustrated.
In addition, unless expressly stated to the contrary, use of the term "a" is intended to include "at
least one" or "one or more." For example, "a device" is intended to include "at least one device"
or "one or more devices."
Any ranges given either in absolute terms or in approximate terms are intended to
encompass both, and any definitions used herein are intended to be clarifying and not limiting.
Notwithstanding that the numerical ranges and parameters setting forth the broad scope of the
invention are approximations, the numerical values set forth in the specific examples arc reported
as precisely as possible. Any numerical value, however, inherently contains certain errors
necessarily resulting from the standard deviation found in their respective testing measurements.
Moreover, all ranges disclosed herein are to be understood to encompass any and all subranges
(including all fractional and whole values) subsumed therein.
Furthermore, the invention encompasses any and all possible combinations of some or all
of the various embodiments described herein. Any and all patents, patent applications, scientific
papers, and other references cited in this application, as well as any references cited therein, are
hereby incorporated by reference in their entirety. It should also be understood that various
changes and modifications to the presently preferred embodiments described herein will be
apparent to those skilled in the art. Such changes and modifications can be made without
departing from the spirit and scope of the invention and without diminishing its intended
advantages. It is therefore intended that such changes and modifications be covered by the
appended claims.

CLAIMS
The claimed invention is:
1. A composition comprising the following formula and optionally salts thereof:
wherein R1, R2, and R 3 are each independently CnH2n+1 or benzyl;
wherein R4 is C 4-C30 alkyl or aikenyl;
n is an integer from 0 to 10; and
X- is a counterion;
optionally further comprising at least one polar or nonpolar solvent or a mixture
thereof.
2. The composition of claim 1, wherein each alkyl is independently selected from the
group consisting of: a straight chain alkyl, a branched chain alkyl, a cyclic alkyl, a saturated
version of the foregoing, an unsaturated version of the foregoing, and combinations thereof.
3. The composition of claim 1, wherein the alkyl for each of R1, R2, and R 3 is
independently selected from the group consisting of: methyl; ethyl; propyl; butyl; pentyl; hexyl;
heptyl; octyl; nonyl; decyl; and combinations thereof.
4. The composition of claim 1, wherein the alkyl for R4 is selected from the group
consisting of: butyl; pentyl; hexyl; heptyl; octyl; nonyl; decyl; and combinations thereof.
5. The composition of claim 1, wherein R2 and R 3 are methyl.
6. The composition of claim 1, wherein R2 and R 3 are butyl or n-butyl.
7. The composition of claim 1, wherein the counterion comprises at least one halide.
8, The composition of claim 1, wherein the counterion is at least one carboxylate.
9. The composition of claim 8, wherein the at least one carboxylate is selected from at
least one of the following: reaction with mineral acid; acrylic acid; acetic acid; methacrylic acid;
glycolic acid; thioglycolic acid; propionic acid; butyric acid; and combinations thereof.
10. The composition of claim 1, comprising at least one or any combination of the
following formulas (1) to (V) and optionally salts thereof:
wherein R is at least one or a mixture of saturated or unsaturated C8, C10, C 12 , C 14, C16,
and C18.
11. The composition of claim 10, wherein R is derived from cocoamine.
12. The composition of claim 1, further comprising at least one component selected
from: thermodynamic hydrate inhibitors, one or more kinetic hydrate inhibitors, one or more
additional anti-agglomeranls, asphaltene inhibitors, paraffin inhibitors, corrosion inhibitors, scale
inhibitors, emulsifiers, water clarifiers, dispersants, emulsion breakers, and combinations thereof.
13. The composition of claim 1, further comprising at least one solvent selected from the
group consisting of: isopropanol, methanol, ethanol, 2-ethylhexanol, heavy aromatic naphtha,
toluene, ethylene glycol, ethylene glycol monobutyl ether (EGMBE), diethylene glycol
monoethyl ether, xylene, and combinations thereof.
14. A method of inhibiting the formation of hydrate agglomerates in a fluid comprising
water, gas, and optionally, liquid hydrocarbon comprising adding to the fluid an effective antiagglomerant
amount of the composition of claim 1, wherein the fluid is optionally contained in
an oil or gas pipeline or refinery.
15. The method of claim 15, wherein said fluid has a salinity of 0% to 25% w/w percent
TDS and/or wherein said fluid has a water cut from 1 to 80% v/v total dissolved solids.