COMPOSITIONS ET METHODES PERMETTANT D'ATTENUER OU D'EMPECHER L'EMULSIFICATION DANS LES GISEMENTS D'HYDROCARBURES

COMPOSITIONS AND METHODS FOR MITIGATING OR PREVENTING EMULSION FORMATION IN HYDROCARBON BODIES

Abrégé français

La présente invention concerne généralement latténuation démulsions, plus particulièrement des émulsions de carboxylate de sodium, dans des gisements dhydrocarbures. En particulier, linvention concerne des compositions utiles dans latténuation démulsions telles que des émulsions de carboxylate de sodium dans des réservoirs dhydrocarbures tels que des réservoirs de pétrole brut. La composition vise latténuation ou la prévention de la formation dune émulsion entre lacide naphténique et des cations métalliques dans un gisement dhydrocarbures, y compris au moins une amine alcoxylée et au moins un acide et/ou un alcool. Linvention concerne en outre des méthodes datténuation de telles émulsions en utilisant les compositions de linvention. Linvention concerne également des méthodes et des compositions pour la complétion de puits de pétrole.

Abrégé anglais

The present invention relates broadly to the mitigation of emulsions, particularly sodium carboxylate emulsions, in hydrocarbon bodies. In particular, the invention relates to compositions useful for mitigating emulsions such as sodium carboxylate emulsions in hydrocarbon reservoirs, such as crude oil reservoirs. The composition for mitigating or preventing the formation of an emulsion between naphthenic acid and metal cations in a hydrocarbon body, including at least one alkoxylated amine and at least one acid and/or alcohol. The invention further relates to methods of mitigating such emulsions utilising the compositions of the invention. The invention also relates to methods and compositions for completion of oil wells.

Revendications

26
THE CLAIMS DEFINING THE INVENTION ARE AS FOLLOWS:
1. A composition for mitigating or preventing the formation of an emulsion
between naphthenic acid and metal cations in a hydrocarbon body, the
composition Including at least one alkoxylated amine and at least one acid
and/or alcohol.
2. The composition of claim 1, wherein the at least one alkoxylated amine
has
the formula:
<IMG>
where R represents an alkyl chain having between one and ten carbon atoms,
X represents a halogen, nitrate or acetate group and n is any integer between
1 and 8.

27
3. The composition of claim 1, wherein the at least one alkoxylated amine
includes an alkyldiamine ethoxylate and/or a tallowalkylamine ethoxylate
propoxylates.
4. The composition of claim 1, wherein the alkoxylated amine includes a
mixture
of alkoxylated fatty amines with carbon chain length from C10- C24 and fatty
amines with carbon chain length between C12- C24.
5. The composition of claim 1, wherein the alkoxylated amine includes a
quaternary amine of the type:
<IMG>
where R1 is (CH2CH2O)n H and R is a saturated or unsaturated alkyl chain with
carbon numbers varying from C10-C16 and having an average number of
ethoxylate units of from 10 to 20.
6. The composition of claim 1, wherein at least two alkoxylated amines are
included.
7. The composition of claim 1, wherein the at least one alkoxylated amine
is
present in the amount of up to about 5% w/w.
8. The composition of claim 1, wherein the at least one acid is selected
from the
group consisting of sulphuric acid, hydrochloric acid, phosphoric acid,
glacial
acetic acid, propanoic acid, benzoic acid, benzene sulphonic acid, dodecyl
benzene sulphonic acid and isopropylamine dodecyl benzene sulphonic acid.
9. The composition of claim 1, wherein the at least one alcohol is selected
from
the group consisting of methanol, ethanol, propanol, isopropanol, butanol and
2-butoxyethanol.

28
10. The composition of claim 1, wherein the composition includes at least
one acid
and at least one alcohol.
11. The composition of claim 1, wherein the at least one acid is present in
the
amount between about 30 to 80%.
12. The composition of claim 1, wherein the at least one alcohol is present
in the
amount between about 10 to 60%.
13. The composition of claim 1, further including at least one demulsifier
selected
from the group consisting of an alkylene oxide block polymer demulsifier with
a
relative solubility in the range of from 5 to 7, an alkyl phenol/formaldehyde
resin
ethoxylate demulsifier with a relative solubility in the range of from 7 to 9,
and
a mixture of triol ester and tetrol demulsifier with a relative solubility in
the
range of from 5 to 7.
14. A method for mitigating or preventing the formation of an emulsion
between
naphthenic acid and metal cations in a hydrocarbon body including contacting
a composition including at least one alkoxylated amine with the hydrocarbon
body.
15. The method of claim 14, wherein the metal cation is selected from the
group
consisting of sodium, potassium, calcium, magnesium or a mixture thereof.
16. The method of claim 14, wherein the emulsion is a sodium carboxylate
emulsion.
17 The method of claim 14, wherein the composition further includes an acid
or
an alcohol or a mixture thereof.
18. The method of claim 14, wherein the composition is dissolved in an
aqueous
solution prior to contact with the hydrocarbon body.

29
19. The method of claim 18, wherein the aqueous solution includes at least
one
species selected from the group consisting of NaCl, KCl, NaHCO3, KHCO3,
Na2CO3, K2CO3, CaCl2, CaBr2, NaOH, a liquid polyamine and a clay stabiliser.
20. The method of claim 14, wherein the composition is contacted with the
hydrocarbon body simultaneously with or after deprotonation of the naphthenic
acid.
21. The method of claim 14, wherein the hydrocarbon body is a near well-
bore
reservoir and the composition is contacted with the near well-bore reservoir
at
a time suitable to mitigate or prevent a wettability shift in the near well-
bore
reservoir, thereby preventing precipitation of species in porous media in the
near well-bore reservoir.
22. The method of claim 14, wherein the composition is contacted with the
hydrocarbon body at a temperature between about 40 and 85°C.
23. The method of claim 14, wherein the at least one alkoxylated amine has
the
formula:
<IMG>
OR

30
<IMG>
where R represents an alkyl chain having between one and ten carbon atoms,
X represents a halogen, nitrate or acetate and n is any integer between 1 and
8.
24. The method of claim 14, wherein the at least one alkoxylated amine
includes
an alkyldiamine ethoxylate and/or a tallowalkylamine ethoxylate propoxylates.
25. The method of claim 14, wherein the alkoxylated amine includes a
mixture of
alkoxylated fatty amines with carbon chain length from C10- C24 and fatty
amines with carbon chain length between C12- C24.
26. The method of claim 14, wherein the alkoxylated amine includes a
quaternary
amine of the type:
<IMG>
where R1 is (CH2CH2O)n H and R is a saturated or unsaturated alkyl chain with
carbon numbers varying from C10- C16 and having an average number of
ethoxylate units of from 10 to 20.
27. The method of claim 14, wherein the composition further includes at
least one
demulsifier selected from include an alkylene oxide block polymer demulsifier
with a relative solubility in the range of from 5 to 7, an alkyl

31
phenol/formaldehyde resin ethoxylate demulsifier with a relative solubility in
the range of from 7 to 9, and a mixture of triol ester and tetrol demulsifier
with
a relative solubility in the range of from 5 to 7.
28. A completion fluid for an oil well including a composition as defined
in claim 1.
29. The completion fluid of claim 28, wherein the completion fluid also
includes
water.
30. A method for completion of an oil well including pumping a completion
fluid as
claimed in claim 28 or 29 into the oil well.

Description

CA 02638266 2008-07-23
COMPOSITIONS AND METHODS FOR MITIGATING OR PREVENTING
EMULSION FORMATION IN HYDROCARBON BODIES
FIELD OF THE INVENTION
The present invention relates broadly to the mitigation of emulsions,
particularly
sodium carboxylate emulsions, in hydrocarbon bodies. In particular, the
invention
relates to compositions useful for mitigating emulsions such as sodium
carboxylate
emulsions in hydrocarbon reservoirs, such as crude oil reservoirs. The
invention
further relates to methods of mitigating such emulsions utilising the
compositions of
the invention. The invention also relates to methods and compositions for
completion
of oil wells.
BACKGROUND TO THE INVENTION
The formation of precipitates or emulsions in crude oil during extraction and
refinement presents a plethora of problems. For example, the formation of
precipitates in pipelines may result in the slowing or complete cessation of
oil flow.
Removal of these precipitates is often difficult, expensive and hazardous to
human
health. The formation of stabilized emulsions delays the production of oil for
future
sale and use, and also has a deleterious effect on the quality of the oil.
Overall, the
formation of precipitates and emulsions in crude oil decreases the efficiency
of
extraction and refinement processes.
The formation of precipitates or emulsions in crude oil generally results from
the
reaction of metal cations with indigenous naphthenic acids. In this context,
naphthenic acids are generally considered to be complex mixtures of alkyl-
substituted acyclic and cyclic carboxylic acids that are generated from in-
reservoir
biodegradation of petroleum hydrocarbons. They are normal constituents of
nearly all
crude oils and are typically present in amounts of up to 4 % by weight. They
are
predominantly found in immature heavy crudes, whereas paraffinic crudes
normally
have lower naphthenic acid contents. Metal cations found in crude oil that are
involved in precipitate and emulsion formation include alkali and alkali-earth
metals

CA 02638266 2008-07-23
2
such as sodium, potassium, calcium and magnesium. Transition metals such as
iron
may also be involved.
There are two common types of precipitate/emulsion that are formed as a result
of
the reaction between metal ions and naphthenic acids in crude oil:
(1) Calcium naphthenates
These are generated from heavy crude oils with high levels of carboxylic acids
and
are formed as a result of a reaction between a naphthenic acid and a calcium
cation.
The properties of calcium naphthenates pose unique challenges in terms of flow
assurance such as:
= plugging of chokes, valves, pumps and vessel internals;
= blocking of water legs in separators due to migration into the water
phase;
= unplanned shutdowns due to hardened deposits causing blockages;
= disposal issues due to presence of heavy metals which can lead to high
NORM activity;
= negative impact on water quality due to an increased oil content in the
separated water; and
= negative impact on injection / disposal well performance.
(2) Sodium carboxvlates
These are generated by the reaction of monocarboxylic acids in crude oil and
sodium
ions in the water phase and are often referred to as carboxylate soaps. They
produce
flow assurance challenges that are different to calcium naphthenates, in
particular
= they form ultra stable viscous emulsions which accumulate at the interface
of
the oil and water components in a separator thereby reducing the residence
time and efficiency of separation;
= sludges of carboxylate soaps can reduce storage and export tank capacity
making it difficult for removal from the tanks;
= toxic sludges may be produced; and
= oil-wet soap particles may be discharged in the separated water.

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3
It is recognised that naphthenic acid salts, commonly referred to as "soaps"
in the oil
industry, are present in a variety of hydrocarbon sources. The issue is
predicated by
high Total Acid Number (TAN), indicating significant amounts of naphthenic
acid
specified by the general formula R-COOH, but more specifically described in
the
literature as carboxylic acids of cyclic and acyclic types as noted above. The
naphthenic acids may be further subdivided between naphthenic acids causing
calcium naphthenate solids and sodium carboxylate solids.
When exposed to precise conditions, naphthenic acids partition from the oil
phase to
the aqueous phase. The main factors believed to play a role in "soap"
formation can
be divided into production chemistry issues of crude oil composition,
production
water and pH variations and physical parameters such as pressure, temperature,
co-
mingling of fluids, shear, and water-cut. The partitioning of naphthenic acids
under
precise conditions may lead to production problems, including solids formation
and
emulsification, at the reservoir wellbore interface and throughout the surface
facilities,
such as pipelines and separators (i.e. as listed above).
Once such particulate matter is formed in porous media, formation damage may
occur
through change in wettability and permeability impairment by various
mechanisms.
Particularly, a tight emulsion incorporating solids as discussed above may be
formed
and move along the interface during fluid flow in the reservoir porous medium
and
may be captured at the pore throats where the flow area is constricted and
wettability
shift may occur. The formation of sodium carboxylate soaps and their
subsequent
precipitation in the porous medium may cause major formation damage problems
in
the production of naphthenic acid containing crude oils.
Hence, the present invention in certain embodiments relates to mitigating the
formation of sodium carboxylate soaps (i.e. emulsions) in porous media and
thereby
alleviating or avoiding the subsequent formation damage caused by these
materials.
Sodium carboxylate "soaps" are formed by contact of acidic crude oil with high
pH
brine or similar aqueous media. Sources of water effective in naphthenate soap
formation include the connate water present in the reservoir, water injected
for
secondary recovery purposes, filtrate of water based mud invading the near-
wellbore

CA 02638266 2008-07-23
4
formation and completion fluids invading the near-wellbore formation, or the
water
entrained as a result of the water conning phenomenon. The prompting process
for
the formation of sodium carboxylate soap is the contact of acidic crude and
fluid are
described in the following.
6
With regard to the reaction chemistry within the system, the formation water
is
usually saturated with CO2 establishing an equilibrium under the reservoir
pressure,
temperature, and brine pH conditions. Carbon dioxide (CO2) contained in
formation
fluids in the reservoir controls the system pH. CO2 dissociates to bicarbonate
and
lo further into carbonic acid during production transmittal As a result of
pressure
decreases, the pH of the water increases allowing the carboxylic acids in the
crude
oil to partition to some degree into the water phase where they may react with
sodium cations to form soap. The change in pH is deemed a function of pressure
decrease related to CO2 content in the crude oil.
Hence, the H+ concentration decreases and equilibrium shifts as the pressure
drop
triggers the degassing of CO2 during the flow of fluids under a pressure
gradient, for
example lifting from a high pressure well bore to a low pressured process
facility.
This reduction in the protons yields excess OH" and increases the pH in the
water.
In the case of drilling fluid filtrate and completion fluid introduction, the
connate water
pH is increased by the introduction of highly buffered high pH fluids meant to
prevent
swelling of resident clays in the near wellbore-reservoir interface. This
direct
introduction leads to immediate excess OH- and increases the pH.
The invention, at least in some embodiments, advantageously provides for the
inhibition of sodium carboxylate emulsions in the near well bore-reservoir
brought
about by the introduction of completion fluids.
Various chemical additives have been used to mitigate the formation of
precipitates
or emulsions in crude oil. For example, US 2005/0282711 Al and US 2005/0282915
Al (both to Ubbels et al.) disclose surfactant compositions containing
hydrotopes
such as mono- and diphosphate esters and methods for inhibiting the formation
of

CA 02638266 2008-07-23
naphthenate salts at oil-water interfaces. WO 2007/065107 A2 (Baker Hughes
Inc.)
discloses a method for inhibiting the formation of naphthenic acid solids or
emulsions
in crude oil in and / or downstream from an oil well. Significantly, the
method requires
the addition of an inhibitor such as a surfactant or a quaternary ammonium
5 compound to the oil at a point prior to or concurrent with the
deprotonation of the
naphthenic acids, otherwise the inhibitor becomes less or perhaps completely
ineffective at preventing the formation of precipitates and emulsions.
SUMMARY OF THE INVENTION
In one aspect of the invention there is provided a composition for mitigating
or
preventing the formation of an emulsion between naphthenic acid and metal
cations
in a hydrocarbon body, the composition including at least one alkoxylated
amine and
at least one acid and/or alcohol.
As already noted, in the context of hydrocarbon bodies, such as crude oil
reservoirs,
"naphthenic acid" includes a complex mixture of carboxylic acids.
Consequently, the
term should be read as such in this specification and should not be construed
as
particularly limited. The naphthenic acid may be present in its acidic neutral
form or
may be dissociated into naphthenate anions. Generally, the naphthenic acid is
dissociated into naphthenate anions.
The metal cation taking part in the emulsion is generally an alkali metal or
an alkaline
earth metal. More particularly, the metal cation will generally be a sodium,
potassium,
calcium or magnesium cation.
The emulsion predominantly contains sodium carboxylate species formed from
naphthenic acid, which may be in the form of naphthenate anions as discussed
above, and sodium cations.
The alkoxylated amine utilised in the composition is preferably a tertiary or
quatemary alkyl-substituted amine wherein the alkyl groups have been further
substituted with one or more alkoxyl groups. Optionally, the alkyl groups may
also be
substituted with one or more tertiary amino groups which may also be
substituted

CA 02638266 2008-07-23
=
6
with alkoxyl groups. Preferred alkoxyl groups of the invention include
methoxyl,
ethoxyl and propoxyl groups. In addition, the alkoxyl groups may also be
substituted
with one or more hydroxyl groups. Even more preferably, the hydroxyl groups
are
located at the termini of the alkoxyl groups. Preferred alkoxylated amines for
use in
the present invention have the following structure:
cH2¨cH2cH240¨cH2cH210H
R-CH2-N-CH2CH2CH2N
CH2 CH2-CH2CH210-CH2CH2I-OH
cH2-fcl¨cH2cH2-1-0H
wherein R represents an alkyl chain having between one and ten carbon atoms
and
n is any integer between 1 and 8. Preferably, n is an integer between 4 and 7.
Other preferred alkoxylated amines for use in the present invention have the
following structure:
cH2 ¨cH2cH2 to --cH2cH210H
R-CH2N
CH2-CH2CH210-CH2CH2-1-0H
where R represents an alkyl chain having between one and ten carbon atoms and
n
is any integer between 1 and 8. Preferably, n is an integer between 4 and 7.
Further preferred alkoxylated amines suitable for use in the present invention
are
those with the following structure:
cH2¨CH2cH210¨cH2cH2-1-0H
I
R-CH2N+-CH3 X-
CH2-CH2CH210-CH2CH2-1-0H

CA 02638266 2015-07-03
7
where R represents an alkyl chain having between one and ten carbon atoms, X
represents a halogen, nitrate or acetate group and n is any integer between 1
and 8.
More preferably, n is an integer between 4 and 7.
Additional examples of alkoxylated amines suitable for use in the present
invention
include alkyldiamine ethoxylates, tallowalkylamine ethoxylate propoxylates.
Other
examples include mixtures of alkoxylated fatty amines with carbon chain length
from
C10- C24, preferably C14- C18 and fatty amines with carbon chain length
between C12-
C24, preferably C14-C18 (e.g. Armorhilo228 by Akzo Nobel).
Other examples of alkoxylated amines suitable for use in the present invention
include quaternary amines of the type:
CH2-R1
4/
R ______ N CH3
\CH2-R
where R1 is (CH2CH20)H and R is a saturated or unsaturated alkyl chain with
carbon numbers varying from C10- C16, more preferably from C10-C13, and having
an
average number of ethoxylate units of from 10 to 20, more particularly from 3-
18 (e.g.
Armorhib231 by Akzo Nobel).
The compositions of the invention may contain one or more alkoxylated amine.
Preferably, the compositions contain two alkoxylated amines. The composition
generally contains up to 5% w/w of the alkoxylated amines, more preferably
about
2.5 to 5% w/w.
Other components of the composition may include alcohols and organic and
inorganic acids. Preferred alcohols include methanol, ethanol, propanol,
isopropanol,
butanol and substituted alcohols such as 2-butoxyethanol. The most preferred
alcohols are isopropanol and 2-butoxyethanol. Suitable acids include sulphuric
acid,
hydrochloric acid, phosphoric acid, glacial acetic acid, propanoic acid,
benzoic acid,
benzene sulphonic acid, dodecyl benzene sulphonic acid and isopropylamine

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8
dodecyl benzene sulphonic acid. Most preferably, phosphoric acid, dodecyl
benzene
sulphonic acid and isopropylamine dodecyl benzene sulphonic acid are utilised.
The composition may contain more than one alcohol and/or more than one acid.
Preferably, the composition contains an acid and an alcohol. Even more
preferably,
the composition contains two or more acids and at least one alcohol. The
compositions generally contain between about 10 and 60% of the alcohol
components and about 30 to 80% of the acid components.
The composition may also include further additives, particularly demulsifiers.
For
example, the composition may also include an alkylene oxide block polymer
demulsifier with a relative solubility in the range of from 5 to 7, such as
Majorchem
DP-314, an alkyl phenol/formaldehyde resin ethoxylate demulsifier with a
relative
solubility in the range of from 7 to 9, such as Majorchem DP-282, and/or a
mixture of
triol ester and tetrol demulsifier with a relative solubility in the range of
from 5 to 7,
such as Basreol P DB-2289.
While not wanting to be bound by any theory as to why the compositions of the
invention are effective, it is believed the alkoxylated amines in the
compositions
exhibit surface-active properties that cause the alkoxylated amine to align
and
combine with free sodium carboxylate in a layer at the oil-water interface and
thereby
prevent interactions between organic acids in the oil phase with cations or
cation
complexes in the water phase.
In another aspect of the invention there is provided a method for mitigating
or
preventing the formation of an emulsion between naphthenic acid and metal
cations
in a hydrocarbon body including contacting a composition including at least
one
alkoxylated amine with the hydrocarbon body.
The composition may be contacted with the hydrocarbon body at any suitable
time.
In some embodiments, the composition is contacted with the hydrocarbon body
simultaneously with or after deprotonation of the naphthenic acid. In
particular
embodiments the composition is contacted with the hydrocarbon body at a time
suitable to mitigate or prevent a wettability shift in the hydrocarbon body.
This

CA 02638266 2008-07-23
9
advantageously prevents precipitation of species, for example in the porous
media in
the near well-bore reservoir, which may cause major formation damage and
consequential processing problems.
In one embodiment, the composition is introduced directly into the hydrocarbon
body
as discussed above. For example, the composition may be introduced directly
into a
near well-bore reservoir where it contacts crude oil in the reservoir. In
certain
embodiments the composition is dissolved in an aqueous solution for use in a
topside
de-salting or washing step of the crude oil prior to further refinement In
these
embodiments, the aqueous solution preferably contains one or more species such
as
NaC1, KCI, NaHCO3, KHCO3, Na2CO3, K2CO3, CaC12, CaBr2, KlagardTm clay
stabiliser, NaOH and liquid polyamines such as UJtrahibTM.
The composition may also be introduced into the crude oil before or after a
precipitate or an emulsion has formed. In addition, two or more compositions
can be
used simultaneously to mitigate a precipitate or emulsion in a sample of crude
oil.
The amount of composition (or compositions if more than one) added to the
crude oil
is generally between 1 and 1000ppm, more preferably between 250 and 700ppm and
even more preferably between 400 and 600ppm.
The rate of separation of aqueous and oil phases is greatly enhanced by the
compositions of the invention relative to untreated oil samples. Complete
separation
generally occurs within 40 minutes of adding a composition to an emulsion.
Often
however, separation is observed within a much smaller time frame of 5 to 10
minutes.
Contact of the composition with the hydrocarbon body may be performed at any
suitable temperature. Preferably, the composition is contacted with the
hydrocarbon
body at a temperature of from about 40 to 85 C, and more preferably at about
65 C.
Again, as will be understood in the art, the naphthenic acid includes a
mixture of
carboxylic acids which may be present in their acidic neutral form or may be
dissociated into naphthenate anions.

CA 02638266 2008-07-23
The metal cation is generally an alkali metal or an alkaline earth metal. More
particularly, the metal cation is generally a sodium, potassium, calcium or
magnesium cation.
5 The emulsion may be a sodium carboxylate emulsion or a mixture of such
emulsions.
This will be appreciated by the description provided above. In certain
embodiments,
the emulsion that is prevented or mitigated is a sodium carboxylate emulsion
that
predominantly contains sodium carboxylate species formed from a naphthenic
acid
and/or naphthenate anions and sodium cations.
The composition utilised in the method may contain any of the alkoxylated
amines
disclosed above. Optionally, the composition for use in the method of the
invention
may contain at least one acid and/or alcohol in accordance with the
composition
described above. Examples of suitable acids include sulphuric acid,
hydrochloric
acid, phosphoric acid, glacial acetic acid, propanoic acid, benzoic acid,
benzene
sulphonic acid, dodecyl benzene sulphonic acid and isopropylamine dodecyl
benzene sulphonic acid. Preferred alcohols include methanol, ethanol,
propanol,
isopropanol, butanol and substituted alcohols such as 2-butoxyethanol.
Likewise, the composition used in accordance with the above described method
may
also include demulsifiers as described above.
In yet another aspect of the invention there is provided a completion fluid
for an oil
well, the completion fluid including at least one alkoxylated amine and at
least one
acid and / or alcohol.
The completion fluid may contain any of the alkoxylated amines, acids,
alcohols
and/or additional demulsifiers described above. It will be appreciated that
that the
quantities of the alkoxylated amine, acid, alcohol and/or demulsifiers in the
completion fluid will depend on the particular oil well to be completed.
Alternatively,
the completion fluid may contain at least one of the compositions described
above. In
any case, the completion fluid may also contain water.

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11
During the completion stage of an oil well, the completion fluid may be
introduced
directly into the well. Alternatively, the completion fluid is dissolved in an
aqueous
solution (unless the fluid already contains sufficient water) prior to
introducing the
solution into the oil well.
Following from the above, according to yet another aspect of the invention
there is
provided a method for completion of an oil well including pumping a completion
fluid
as described above into the oil well.
Embodiments of the invention will now be discussed in more detail with
reference to
the following examples which are provided for exemplification only and which
should
not be considered limiting on the scope of the invention in any way.
BRIEF DESCRIPTION OF THE FIGURES
Figure 1 is a photograph of a mixture of calcium chloride, klagard and a
composition
(Formulation A) of the invention.
Figure 2 is a photograph of the emulsion obtained from stirring the mixture of
Figure
1 with crude oil from a field off the North West coast of Malaysia.
Figure 3 is a photograph showing complete separation of the emulsion in Figure
2
after seven minutes.
26 Figure 4 is a photograph of an emulsion obtained by stirring a mixture
of calcium
chloride, sodium hydroxide, ultrahib and a composition (Formulation A) of the
invention with crude oil from a field off the North West coast of Malaysia.
Figure 5 is a photograph showing separation of the emulsion in Figure 4 after
five
minutes at 65 C.
Figure 6 is a photograph showing separation of the emulsion in Figure 4 after
twenty
minutes at 65 C.

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12
Figure 7 is a photograph taken after 10 minutes of an untreated emulsion of
sample
A production fluid with synthetic brine (left) and the same emulsion treated
with
500ppm of a composition (Formulation D) of the invention (right).
Figure 8 is a photograph taken after 25 minutes of an untreated emulsion of
sample
A production fluid with synthetic brine (left) and the same emulsion treated
with
500ppm of a composition (Formulation 0) of the invention (right).
Figure 9 is a photograph taken after 40 minutes of an untreated emulsion of
sample
A production fluid with synthetic brine (left) and the same emulsion treated
with
500ppm of a composition (Formulation D) of the invention (right).
Figure 10 is a photograph taken after 1 minute of an untreated emulsion of
sample B
production fluid with synthetic brine (left) and the same emulsion treated
with
500ppm of a composition (Formulation D) of the invention (right).
Figure 11 is a photograph taken after 20 minutes of an untreated emulsion of
sample
B production fluid with synthetic brine (left) and the same emulsion
treated with
500ppm of another preferred composition (Formulation D) of the invention
(right).
Figure 12 is a photograph taken after 40 minutes of an untreated emulsion of
sample
B production fluid with synthetic brine (left) and the same emulsion
treated with
500ppm of a composition (Formulation D) of the invention (right).
Figure 13 is a photograph showing residual water and emulsion levels in sample
A
after grind out treatment in the presence of differing concentrations of two
compositions (Formulation A and Formulation D) of the invention.
Figure 14 is a graph of residual emulsion levels in sample A as a function of
time and
concentration of a composition (Formulation A) of the invention.
Figure 15 is a graph of residual emulsion levels in sample A as a function of
time and
concentration of a composition (Formulation D) of the invention.

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13
Figure 16 is a photograph showing residual water and emulsion levels in sample
B
after grind out treatment in the presence of differing concentrations of a
composition
(Formulation D) of the invention.
Figure 17 is a graph of residual emulsion levels in sample B as a function of
concentration of a composition (Formulation D) of the invention.
Figure 18 is a photograph of untreated emulsions of sea water with crude oil.
Figure 19 is a photograph of the samples in Figure 18 after treatment with two
compositions (Formulation B and Formulation E) of the invention.
Figure 20 is a photograph of the initial emulsions obtained from sea water
with crude
oil wherein the sea water was treated with two compositions (Formulation B and
Formulation E) of the invention prior to mixing with crude oil.
Figure 21 is a photograph of the samples in Figure 20 after thirty minutes at
65 C.
Figure 22 is a photograph of untreated emulsions of calcium chloride solution
with
crude oil.
Figure 23 is a photograph taken after five minutes and 65 C of the samples in
Figure
22 after treatment with two compositions (Formulation B (middle) and
Formulation
E(right)) of the invention.
Figure 24 is a photograph taken after thirty minutes at 65 C of an untreated
emulsion
of calcium bromide solution with crude oil (left) and the emulsion wherein the
calcium
bromide solution was treated with 100ppm (middle) and 200ppm (right) of a
composition (Formulation B) of the invention prior to emulsion formation.
Figure 25 is a photograph taken after thirty minutes at 65 C of an untreated
emulsion
of potassium hydrogen carbonate solution with crude oil (left) and the
emulsion after
treatment with a composition (Formulation B) of the invention (right).

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14
Figure 26 is a photograph taken after thirty minutes at 65 C of an untreated
emulsion
of potassium hydrogen carbonate solution with crude oil (left) and the
emulsion
wherein the potassium hydrogen carbonate solution was treated with a
composition
(Formulation B) of the invention prior to emulsion formation (right).
EXAMPLES
Constituent Amount Formulations
Armohiblm 28 2.0 - 2.5 A, B, C
Armohib m 31 1.5 - 2.5 A, B, C, D
2-Butoxyethanol 45 A
Dodecyl benzene
5
sulphonic acid
Glacial acetic acid 42 - 50 A, D
lsopropanol 20 - 42 B, C, D
Isopropyl amine dodecyl
3 A, C
benzene sulphonic acid
Additional Demulsifier 5- 15 A, C, D
Phosphoric acid 45 -75 B, C
Table 1: Compositions of the invention including their % constituents.
An additional formulation was also prepared and is referred to below as
Formulation
E. This is a composition including a blended oxyalkylated phenolic resin and
glycol
ester supplied by TOHO Chemical Industry Co., Ltd. as Demulfer D989 as an
active
constituent.
Example 1
The effectiveness of Formulation A on CaCl2 brine in the presence of klagard
clay
stabiliser to be used in the completion fluid for oil obtained from a field
off the North
West coast of Malaysia was evaluated.

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To a 11.0 lb/gal calcium chloride solution was added 1 % (v/v) Formulation A.
To this
solution 8.0 lb/bbl (wt/vol) klagard solution was added. The appearance of the
solution is shown in Figure 1.
5 Next, a 50:50 mixture of the CaCl2 brine and crude oil was stirred at
101000 rpm for
one minute to create an emulsion as shown in Figure 2. The resultant emulsion
was
then heated in a water bath maintained at 65 C and the water separation was
monitored in five minute increments.
10 Complete separation of the water phase was observed after seven minutes
(Figure
3). The interface was found to be clean. No precipitation or sedimentation was
observed. This example demonstrates (i) that klagard is compatible with 11.0
lb/gal
calcium chloride brine and Formulation A (no precipitation or separation) and
(ii)
demulsification was complete within 7 minutes. A clean interface without any
15 sediment at the bottom was achieved.
Example 2
The effectiveness of emulsion preventive Formulation A in a completion fluid
containing CaCl2 brine with 50% sodium hydroxide as a neutralising agent and
ultrahib was evaluated on oil obtained from a development field off the North
West
coast of Malaysia.
To a 11.0 lb/gal calcium chloride solution was added 1 %(v/v) Formulation A.
50%
sodium hydroxide solution was added slowly to raise the pH from 1.59 to 6.2.
This
also resulted in the precipitation of calcium hydroxide. To this liquid was
added 1%
Formulation A and the pH noted again. Finally, 2% (v/v) ultrahib was added to
this
solution and the pH was noted. This also caused formation of an orange
coloured
liquid.
Next, a 50:50 mixture of the CaCl2 brine and crude oil was stirred at 10000
rpm at
room temperature for one minute to create the emulsion shown in Figure 4. The
resultant emulsion was then heated in a water bath maintained at 65 C and the
separation of water from the oil was monitored every five minutes.

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16
Significant separation of the water phase from the oil phase was observed
after five
minutes as shown in Figure 5. After twenty minutes the separation was deemed
to be
complete (see Figure 6).
This example demonstrates that the composition Formulation A completely
separates
the emulsion at 65 C in twenty minutes in the presence of ultrahib and sodium
hydroxide.
Example 3
Two oil samples (hereinafter referred to as 'sample A' and ` sample B')
collected
approximately one hour apart from an oil field off the North West coast of
Australia
with known emulsion problems were obtained for testing the compositions of the
invention.
Synthetic water was blended for use in example 3 based on a water analysis
previously provided for scale modelling work. The contents of the blended
water are
shown in Table 2.
Salt Concentration (mg/L)
Chloride 13026.00
Sulphate 179.75
Barium 5.73
Calcium 309.00
Strontium 14.75
Magnesium 86.00
Sodium 8550.30
Potassium 414.50
Bicarbonate 930.00
Acetate 430.00
Table 2: Components of the synthetic water together with their concentration.
Sample A

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17
The following test procedure was performed on sample A in order to ascertain
the
effectiveness of compositions Formulation A and Formulation D of the
invention.
An emulsion was prepared by mixing 50% of sample A with 50% brine at 9500 rpm
for one minute. The resulting emulsion was then decanted in 100 ml increments
into
seven calibrated centrifuge tubes. The centrifuge tubes were left to stand at
65 C in a
water bath. Either one or both of Formulation A or Formulation D was added to
each
centrifuge tube in accordance with the quantities in Table 3.
FORMULATION FORMULATION
Tube number
A (ppm) D (ppm)
1 0 0
2 500 0
3 1000 0
4 0 500
5 0 1000
6 250 250
7 500 500
Table 3: Quantities of Formulation A and Formulation D added to each
centrifuge
tube.
The centrifuge tubes were simultaneously shaken 100 times then left to stand
at
16 65 C in the water bath. Water separation was recorded at intervals of 1,
3, 5, 10, 15,
20, 25, 30 and 40 minutes. The effect of 500ppm of Formulation D on sample A
after
10, 25 and 40 minutes is illustrated in Figures 7 to 9. Untreated and treated
tubes are
shown on the left and right respectively in each figure. The presence of an
emulsion
can be seen on the untreated samples which are characterised by a light brown
"mousse" consistency of the oil. The percentage oil and water separation over
40
minutes is shown in Table 4.
Time Formulation 0 500 1000 0 0 250 500
(min) A PPm PPm PPm
PPm PPm PPm PPm

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18
Formulation 0 0 0 500 1000 250 500
PPm PPm PPm PPm PPm PPm PPm
Tube 1 2 3 4 5 6 7
1 %W 0 2 1 27 2 2 1
%E 100 37 11 12 15 16 33
%0 0 61 88 61 83 82 66
3 %W 1 10 4 42 38 15 7
%E 99 35 13 0 1 12 29
%0 0 55 83 58 61 73 64
%W 4 22 9 42 38 18 18
%E 96 27 9 0 1 6 5
%0 0 51 82 58 61 76 77
%W 24 44 24 42 39 20 23
%E 76 3 6 0 0 2 0
%0 0 53 70 58 61 78 77
40 %W 35 46 36 43 39 22 24
%E 65 0 0 0 0 0 0
%0 0 54 64 57 61 78 76
Table 4: Percentage oil and water separation in sample A over 40 minutes, W =
water, E = emulsion, 0= oil, ppm = parts per million.
5 After recording the 40 minute water drop, the separated water was
syringed from
each tube. The pH of the water was within an acceptable operating range of 6
to 7,
thus negating any corrosion risk associated with injection of the acid-based
Formulation A and Formulation D compositions.
10 A grind out was then performed on the oil remaining in the tubes to
determine the
amount of residual water or emulsion in the oil. Each tube was vigorously
shaken to
create a uniform sample. Then 5 ml from each tube was extracted and placed
into a
10 ml centrifuge tube containing 5 ml of xylene. The 10 ml centrifuge tubes
were
shaken vigorously and centrifuged at maximum speed for 15 minutes. The
residual
water and emulsion were then recorded as a percentage. The results are
depicted in

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19
Figures 14 (for Formulation A) and 15 (for Formulation D) and in Table 5.
Figure 13
shows images of the grind out results for each sample tube.
Tube 1 2 3 4 5 6 7
pH of separated H20 7.83 7.01 - 6.31 - 6.63 5.72 6.68 6.4/
Centrifuge %W 15 1 1.8 1.2 2.4 2 3.2
grind out %E 2 1.4 0 0.4 0.8 1.2 0
%0 83 97.6 98.2 98.4 96.8 96.8 96.8
Table 5: Centrifuge grind out results and pH of separated water from sample A;
W =
water, E = emulsion, 0 = oil, ppm = parts per million.
The grind out results indicate very little residual emulsion within the oil
phase. For
example, after 40 minutes, homogenised samples taken from the untreated oil
layer
still indicate 2 % emulsion present, as opposed to 0.4 % in the sample treated
with
500 ppm of Formulation D. This higher emulsion content in the untreated sample
will
result in a higher viscosity of the crude oil, potentially causing problems in
process
vessels and dehydration systems.
Composition Formulation A was less effective than Formulation D at comparative
dosage rates, displaying slower water drop as well as being less effective in
resolving
the emulsion.
Blending the compositions Formulation A and Formulation D in a 1:1 ratio was
performed to ascertain if there was any synergy between the two products in
treating
sample A. Although this blend performed better than Formulation A alone, it
was not
as effective as Formulation D. Therefore it is concluded that there is no
synergy
between the two products.
Sample B
As Formulation D showed a clear improvement in emulsion resolution over
Formulation A in the above experiments on sample A, corresponding experiments
on
sample B were limited to Formulation D. The same procedure utilised on sample
A
was performed on sample B. The effect of 500ppm of Formulation D on sample B

CA 02638266 2008-07-23
after 1, 20 and 40 minutes is illustrated in figures 10 to 12. Untreated and
treated
tubes are shown on the left and right respectively in each figure. As for
sample A, the
presence of an emulsion can be seen on the untreated samples which are
characterised by a light brown "mousse" consistency of the oil. The emulsion
is
6 tighter in sample B relative to sample A as is evident from the
poorer water drop in
the untreated sample. This was confirmed by the grind out result which showed
a
higher residual emulsion and water content within the oil phase (see below).
The
percentage oil and water separation over 40 minutes is shown in Table 6.
Time Formulation 0
400 500 600 700 800 900 1000
(min) D
PPm PPm PPm PPm PPm PPm PPm PPm
Tube 1 2 3 4 5 6 7 8
1 %W 0 5 15 3 10 10 3 40
%E 100 0 0 0 0 0 0 0
%0 0 95 86 97 90 90 97 60
3 %W 0 45 45 49 45 45 35 47
%E 100 0 0 0 0 0 0 0
%0 0 55 55 51 55 55 65 53
5 %W 0 49 49 49 49 48 48 49
%E 100 0 0 0 0 0 0 0
= %0 0 51 51 51 51 52 52
51
10 %W 1 49 49 49 49 49 48 50
%E 99 0 0 0 0 0 0 0
%0 0 51 51 51 51 51 52 50
40 %W 12 49 49 49 49 49 48 50
%E 88 0 0 0 0 0 0 0
%0 0 51 51 51 51 51 52 50
Table 6: Percentage oil and water separation in sample B over 40 minutes, W =
water, E = emulsion, 0= oil, ppm = parts per million.
Figure 16 shows images of the grind out results of sample B for each
Formulation D
concentration. The results are also presented quantitatively in Figure 17 and
Table 7.

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=
21
After 40 minutes, homogenised samples taken from the untreated oil layer still
indicate 6 % emulsion present, as opposed to 0.8 % in the samples treated with
400
or 500 ppm of Formulation D.
Tube 1 2 3 4 5 6 7 8
pH of thieved H20 7.96 7.7 7.36
5.74 7.06 6.88 6.29 5.85
Centrifuge %W 36 1.6 1.6 1 0.4 0.8 0.8 4
grind out %E 6 0.8 0.8 4.7 2 2 3.2 6.4
%0 58 97.6 97.6 94.3 97.6 97.2 96 89.6
Table 7: Centrifuge grind out results and pH of separated water from sample A;
W =
water, E = emulsion, 0 = oil, ppm = parts per million.
Signs of over treatment were observed with dosage rates above 500ppm of
Formulation D on sample B, presenting with higher residual emulsion content
within
the oil phase. For sample B, the optimum dose of Formulation D for achieving
minimal residual emulsion levels was around 400 to 500ppm (see Figure 17 and
Table 7).
The Formulation D composition maintained its excellent performance on sample
B,
achieving acceptable results at similar dosage rates as required for sample A.
This
suggests that Formulation D will be effective in handling production system
upsets
and/or periods of instability.
Example 4
The emulsion prevention characteristics of the compositions of the invention
were
further tested in conjunction with four aqueous phases to be used as
completion
fluids on an oil sample obtained from an oil field off the North West
Malaysian coast.
The oil was obtained from a drill seam test.

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22
The following completion fluids were tested:
1. Actual Sea water (collected from Perth sea shore) with a pH of 7.7. The
water
was filtered through a Whatmann No. 1 filter paper using a sintered glass
funnel.
2. 10.5 lb/gal CaCl2 solution prepared in the laboratory by dissolving
CaCl2.2H20 in deionised water
3. 12.5 lb/gal CaBr2solution, prepared by dissolving CaBr2.H20.
4. 10.51b/gal KHCO3 solution prepared by dissolving KHCO3 in water (the
dissolution was not complete and only supematant liquid was used for the test
purposes).
1. Actual sea water and crude oil
Set 1 ¨ Compositions added after the emulsion was formed
An emulsion was prepared by mixing 50 % sea water completion fluid and 50 %
crude oil at 10000 rpm for one minute. The resulting emulsion was then poured
into
100 ml centrifuge tubes. Figure 18 represents the stable and viscous emulsion
formed when sea water was mixed with crude oil.
100 ppm of the compositions of the invention was injected at room temperature
into
each emulsion and the centrifuge tubes were then transferred to a water bath
maintained at 65 C. Water separation was noted at intervals of 1 minute, 2
minutes,
5 minutes, 10 minutes, 20 minutes and 30 minutes. Centrifuge tubes were then
removed from the water bath. Figure 19 represents the samples after 30
minutes.
It was observed that Formulation B was able to resolve 100% emulsion within
first 10
minutes. In fact, Formulation B very clearly separated the water from the oil
without
any emulsion pad. The interface is also sharp and clear. Another composition
EBK
205 was able to resolve 95% of the emulsion within the stipulated test period.

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23
Set 2¨ Compositions added to the sea water prior to emulsion formation
In a mixing vessel 50 ml quantities of sea water were treated with the
compositions of
the invention at the desired dose rate. The fluid was then stirred for 1
minute at 500
rpm to ensure complete mixing of the composition in the system. A 50 ml crude
oil
sample was added and the emulsion prepared by stirring the system at 10000 rpm
for 1 minute. The contents were transferred into 100 ml centrifuge tubes.
Figure 20 shows the initial emulsions are not stable and viscous. Instead the
water
separation appears to have begun. Indeed, almost complete water separation has
already occurred in the centrifuge bottle containing Formulation B even before
further
treatment of the tubes in a water bath. This indicates that when added into
the sea
water phase prior to emulsion formation, Formulation B can prevent emulsion
formation in the system.
Centrifuge tubes containing the oil/water sample were then transferred to a
water
bath maintained at 65 C. Water separation was noted at intervals of 1 minute,
2
minutes, 5 minutes, 10 minutes, 20 minutes and 30 minutes. The tubes were then
removed from the water bath. Figure 21 represents the water separation data
after
minutes at 65 C. Formulation B (tube no. 3) is extremely effective and
produces
clean water and a sharp interface. In contrast, Formulation E (tube no. 5)
does not
seem to be effective as it leaves behind significant untreated emulsion.
25 Based on these results only Formulation B and Formulation E were used for
screening purposes in the remaining completion fluid systems below.
2. Calcium chloride solution (10.5 lb/pal) and crude oil
30 A weak and less stable emulsion formation was observed when the two
phases were
mixed together as represented in Figure 22. Following the emulsification
process,
100 ppm of Formulation B and Formulation E was injected in the centrifuge tube
numbers 2 and 3 respectively. The bottles were transferred to a water bath
maintained at 65 C. Figure 23 indicates the extent of water separation after 5

CA 02638266 2008-07-23
24
minutes. In particular, complete emulsion separation was observed for
Formulation B
and Formulation E. However the separated water quality is better with
Formulation B.
Based on this result, only Formulation B was used for testing the remaining
completion fluid systems.
3. Calcium bromide solution (12.5 lb/clan and crude oil
In this example, composition Formulation B was injected into the calcium
bromide
solution prior to the emulsion formation with crude oil. Figure 24 represents
the water
separation obtained at 65 C after 30 minutes. Clearly, Formulation B is
effective at
resolving the emulsion. At 100 ppm the emulsion is not completely resolved.
However, at 200 ppm the emulsion is completely resolved and the system has a
very
sharp interface with no emulsion pad.
4. Potassium Hydrogen Carbonate solution (10.5 lb/gal) and crude oil
Set 1 ¨ Compositions added after the emulsion was formed
A 50:50 mixture of crude oil and potassium hydrogen carbonate solution was
prepared by mixing crude oil and potassium hydrogen carbonate solution. The
emulsion was separated into two tubes. Formulation B was then injected into
one
tube. The tubes were transferred to a water bath at 65 C for 30 minutes.
Figure 25
indicates the water separation pattern for the blank (left) and the emulsion
treated
with Formulation B (right). Clearly, complete emulsion resolution takes place
in the
emulsion treated with Formulation B.
Set 2¨ Compositions added to the completion fluid prior to emulsion formation
In this set Formulation B was injected in the potassium hydrogen carbonate
solution
prior to mixing the solution with crude oil. Upon heating the treated emulsion
was
resolved very quickly (within first 5 minutes) producing a clear interface.
Figure 26
shows the water separation for the blank (left) and the emulsion treated with
Formulation B (right) after 30 minutes at 65 C.

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Example 4 clearly indicates that Formulation B effectively treats the oil
emulsion on
all of the completion fluid systems at 100 ppm (0.01%) except for the calcium
bromide system where the chemical is effective at 200 ppm (0.02%).
5 It
will of course be realised that the above has been given only by way of
illustrative
example of the invention and that all such modifications and variations
thereto as
would be apparent to persons skilled in the art are deemed to fall within the
broad
scope and ambit of the invention as herein set forth.