CA 02840675 2014-01-17
METHOD FOR DESTABILIZING BITUMEN-WATER AND
OIL-WATER EMULSIONS USING LIME
FIELD OF THE DISCLOSURE
The present disclosure relates to methods and processes for destabilization of
bitumen-
water and heavy-oil-water emulsions and froths, such as emulsions and froths
produced by
processes for extraction of bitumen and heavy oil.
BACKGROUND
As used in this patent specification, the term "bitumen" is intended to denote
a solid or
semi-solid form of petroleum, as distinct from a readily flowable hydrocarbon
substance such as
conventional liquid crude oil. The term "heavy oil" is used herein to denote a
highly viscous
form of crude oil that, although liquid in a strict sense, cannot readily flow
to production wells
under normal reservoir conditions due to its inherent viscosity. "Bitumen"
(which alternatively
may be referred to as "extra heavy oil") typically has in the range of about 7
to 12 API gravity
(API gravity being a measure of crude oil quality based on the density) and
greater than 15%
asphaltenes by mass. "Heavy oil" typically has in the range of about 17 to 22
API gravity and
about 10% asphaltenes. The term "light oil" generally refers to crude oil
having about 25 API
gravity or greater and about 1.5% asphaltenes. The general term "oil" in the
present disclosure
may refer to bitumen, heavy oil, and/or light oil, depending on the context.
As conventional oil resources are being depleted, the world's liquid
hydrocarbon demand
is increasingly supplied by bitumen and heavy oil. Total bitumen contained in
the Athabasca oil
sands deposits in northern Alberta, Canada is estimated at about 1.7 x 1012
barrels, which is
ranked as the world's second largest hydrocarbon resource; only about 10% of
these deposits are
suitable for surface mining while the remaining 90% is suitable for thermal in-
situ processes
such as SAGD and CSS processes. Bitumen-water emulsions are produced by using
both oil-
sands-ore-water slurry based bitumen extraction and steam-assisted bitumen
recovery processes.
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As a result, destabilization of bitumen-water and heavy-oil-water emulsions is
an important
process for the industry.
In the steam assisted in-situ recovery processes, bitumen-water or oil-water
emulsions are
produced in the pores of the reservoir, or during the pumping of bitumen-water
(condensed
steam) and oil-water mixtures from reservoir to the surface facilities.
Regardless of the causes of
the formation of these emulsions, upon the recovery of these emulsions in the
surface facilities
emulsion breaking additives such as light hydrocarbons, synthetic crude oil or
emulsion
destabilizing specialty chemicals are added at different proportions for the
destabilization of the
emulsion structure. Special vessels, mostly operating as flotation cells, are
used for the recovery
of bitumen or heavy oil and water as two separate fluids streams.
Bitumen and heavy oil are commonly produced using steam-assisted thermal in-
situ
recovery processes, such as steam-assisted gravity drainage (SAGD) and cyclic
steam
stimulation (CSS) processes. In these processes, bitumen and heavy oil are
recovered in the
form of bitumen-water or heavy-oil-water emulsions. As used in this patent
specification, the
term "oil-water emulsion" is to be understood as referring to an emulsion
containing heavy oil,
unless otherwise indicated.
Bitumen-water emulsions are also produced during the utilization of surface
mineable oil
sands ore, where bitumen-water emulsions are produced by the oil-sands-ore-
water-slurry-based
extraction processes. Oil-water emulsions are also produced by enhanced oil
recovery methods
such as water flooding processes.
BRIEF SUMMARY
The present disclosure teaches methods and processes for destabilization of
bitumen-water
and oil-water emulsions by treating such emulsions with lime (as calcium oxide
- CaO). In
alternative embodiments of methods and processes in accordance with the
present disclosure, the
emulsions may be treated with the Periodic Table's Group II earth alkali
metals cations such as
magnesium (Mg24), calcium (Ca2+), strontium (Sr2+), and barium (Ba2 ) as
destabilizing additives
for the separation and recovery of bitumen and water (or heavy oil and water)
as separate
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streams. In other embodiments, the Periodic Table's Group III metals cations
such as aluminum
(A131-) may be used as destabilizing additives, with such cations being most
effective as additives
to acidic emulsions (i.e., having a pH less than 7.0).
Processes in accordance with the present disclosure also promote flocculation
of the clay
particles and precipitates naphthenic acids salts, by which they are separated
from the emulsion
fluids; and, improves chemistry of the recovered water for its recycling to
the extraction plant or
for its use for any purpose. The present disclosure has applications in oil
production and clean-
up of contaminated soils with hydrocarbons and/or organic substances.
The present disclosure teaches methods and processes for destabilizing
emulsions having
to
constituents including water, hydrocarbons (or other organic substances), and
solids, to facilitate
separation of these constituents. Examples of emulsions that may be treated
using methods and
processes in accordance with the present disclosure include (but are not
limited to):
(i) bitumen-water emulsions produced by ore-water-slurry-based processes for
extraction of bitumen from surface-mined oil sands ore;
(ii) bitumen-water emulsions produced by in-situ bitumen extraction processes
including
SAGD and CSS processes;
(iii) bitumen-water emulsions in the form of froth produced by ore-water-
slurry-based
bitumen extraction processes;
(iv) oil-water emulsions produced by water flooding or other enhanced oil
recovery
processes; and
(v) oil-water-solids emulsions and or suspensions for the clean-up of
contaminated soils
with hydrocarbons and/or other organic substances.
Bitumen-water and heavy-oil-water emulsions produced by SAGD, CSS, or water
flooding
processes typically contains about 15% to 30% bitumen or heavy oil, and a
small amount
(typically about or less than 1%) of inorganic solids. The major fraction of
the solids is typically
composed of silt and clay particles, which are also called fines, which term
is commonly used to
denote particles passing a 320 mesh (i.e., 45 micron) screen. Bitumen and
solids contents of the
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froth produced by ore-water-slurry-based extraction processes are generally
higher; a typical
composition of such froth is about 60% bitumen, 30% water, and 10% solids
(with the major
fraction of the froth solids consisting of silt and clay particles). Solids
accumulate at the
bitumen-water interface and have to be flocculated and separated from the
bitumen or heavy oil.
The solids contained in these emulsions have to be considered in the design of
bitumen-water-
emulsion-destabilizing processes; they have to be flocculated and separated
from the emulsion.
The present disclosure teaches methods for:
(i) destabilization of emulsions to separate the constituent solids,
bitumen (or heavy oil),
and water to facilitate recovery of the bitumen (or heavy oil) and water as
separate
streams;
(ii) flocculation of silt and clay particles and their precipitation and
separation from the
emulsion fluids;
(iii) improvement of the chemistry of the recovered water (alternatively
referred to as
"release water") for recycling to bitumen or heavy oil recovery processes; and
(iv) destabilization of hydrocarbon-water-solids emulsions and/or suspensions
to
facilitate clean-up of soils contaminated with hydrocarbons and/or other
organic
substances.
Bitumen contained in Athabasca oil sands deposits, Alberta, Canada is
estimated at about
1.7 x 1012 barrels, which is ranked as the world's second largest hydrocarbon
resources. Only
about 10% of these deposits are suitable for surface mining, while the
remaining 90% is suitable
for thermal in-situ recovery processes such as SAGD and CSS. Bitumen-water
emulsions are
produced by using both ore-water-slurry-based bitumen extraction and steam-
assisted bitumen
recovery processes. As a result, destabilization of bitumen-water and heavy-
oil-water emulsions
is an important process for the industry.
In steam-assisted in-situ recovery processes, bitumen-water or oil-water
emulsions are
produced in the pores of the subsurface reservoir, or during the pumping of
bitumen-water
(condensed steam) and oil-water mixtures from the reservoir to the surface
facilities. Regardless
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of the causes of the formation of these emulsions, upon the recovery of these
emulsions in the
surface facilities, emulsion-breaking additives such as light hydrocarbons,
synthetic crude oil,
and/or emulsion-destabilizing specialty chemicals are added to destabilize the
emulsion
structure. Special process vessels, most typically operating as flotation
cells, are used for the
recovery of bitumen (or heavy oil) and water as separate fluid streams.
High alkalinity of the water in the reservoir (which could be the connate
water and/or water
formed by condensed steam) increases the solubility of naturally-occurring
naphthenic and
asphaltic acids in bitumen or heavy oil which act as surfactants and reduce
bitumen-water or oil-
water interfacial tension. Reduction in bitumen-water or oil-water interfacial
tension is a
primary mechanism in the formation of bitumen-water or oil-water emulsions.
Low bitumen-
water or oil-water interfacial tension increases the attraction of bitumen or
oil droplets to water,
reducing the probability of coalescence of bitumen or oil droplets when the
emulsions are treated
by mixing or flotation processes for purposes of separating the bitumen or oil
from water.
Methods and processes as disclosed herein increase bitumen-water or oil-water
interfacial
tension by reducing or eliminating surfactant species with Ca2+ introduced by
CaO addition into
the emulsions. Therefore, the disclosed methods and processes increase the
hydrophobic
characteristics of bitumen and oil droplets in emulsions and make them more
attractive to each
other and to gas bubbles (e.g., air, flue gas) since most of the gas bubbles
are also hydrophobic.
The attraction of bitumen (and oil) droplets to gas bubbles makes facilitates
more effective
recovery of bitumen (or oil) by flotation-type processes that form bitumen-
rich (or oil-rich)
froth-type products.
The present disclosure is directed to methods and processes for increasing the
bitumen-
water or oil-water interfacial tension in bitumen-water or oil-water
emulsions, thereby promoting
breakdown of the emulsion structure and resultant destabilization of the
emulsions, and
facilitating separation and recovery of bitumen and water (or oil and water)
different products.
Methods and processes in accordance with the present disclosure also promote
flocculation of
silt and clay-size particles by reducing the activities of surfactant species
and thereby reducing
the wettability of these particles with water and promoting flocculation of
the particles. In
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addition, methods and processes in accordance with the present disclosure
improve the chemistry
of the recovered water and reduce water-soluble naphthenic and asphaltic
acids, thus making the
recovered water more suitable for recycle to bitumen (or heavy oil) recovery
plants.
Because the methods and processes disclosed herein increase the hydrophobic
characteristics of bitumen and oil droplets in emulsions and make them more
attractive to each
other and to gas bubbles (e.g., air, flue gas), the performance of these
methods and processes
may be enhanced by injecting a gaseous substance (such as but not limited to
air, combustion
flue gas, steam, nitrogen (N2) or carbon dioxide (CO2)) injected into the
separation vessel.
Injection of a gaseous substance, as practiced in flotation processes, speeds
up the emulsion
destabilization and facilitates recovery of the bitumen in the form of bitumen-
water-gas froth.
This froth typically contains a small amount of solids, such as clay-size
particles, depending on
the process operating conditions. Turbulence created in the vessel by
injection of gaseous
substance promotes the rate of flocculation of clay-size particles.
The efficiency of the disclosed methods and processes typically will increase
as the process
temperature and pressure are increased. As an example, if such methods and
processes are
implemented for destabilization of bitumen-water or heavy-oil-water emulsions
produced by
SAGD or CSS processes, they will provide much better results if the bitumen-
water or heavy-oil-
water emulsions are processed at the production wellhead temperature and
pressure operating
conditions.
DESCRIPTION
There are two primary causes for the formation of bitumen-water or heavy-oil-
water
emulsions are formed in steam-assisted thermal recovery processes:
(i)
interfacial tension in bitumen-water or heavy-oil-water mixtures is
reduced by the
activation of naphthenic acids naturally present in bitumen and heavy oil by
alkaline water (condensed str\eam) in the reservoir having a pH greater than
7.0
(pH > 7); and
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(ii)
exposure of bitumen-water or heavy-oil-water mixtures to mixing by any
means,
either in the reservoir or in the process of lifting of bitumen-water or heavy-
oil-
water mixture to the surface.
The pH is a measure of acidity of the aqueous systems which is defined as pH =
- log[H+];
i.e., pH is defined as the negative of the logarithm of the molar proton
concentration [H+]. By
this definition, pH = 7 for the neutral aqueous systems; acidity increases as
pH is reduced from 7
to 0 (0 <pH< 7) and alkalinity increases as pH is increased from 7 to 14 (7
<pH< 14).
In the presently-disclosed methods and processes, bitumen-water or heavy-oil-
water
interfacial tension is increased by eliminating the activities of the
functional groups acting as
surfactants by treating the emulsions with one or more additives of ionic
base. These additives
reduce the activity of the functional groups acting as surfactants, thereby
increasing bitumen-
water or oil-water interfacial tension and destabilizing the emulsions. Since
the emulsions'
stability is reduced, they become structurally unstable. Any mechanical
agitation or injection of
a gas stream into destabilized emulsion results in the formation of bitumen-
rich (or oil-rich) froth
at the top of the process vessel. The chemical additives used for the
destabilization of the
emulsions also promote flocculation of clay-size particles in the froth and
improve the chemistry
of the recovered water.
Cost-effective and substantially environmentally-benign chemicals suitable for
use as
additives for purposes of the disclosed methods and processes include the
salts of the Periodic
Tables' Group II earth alkali metals cations such as magnesium (Mg2+), calcium
(Ca2+),
strontium (St2 ), and barium (Ba2+) and the Periodic Tables Group III metals
cations such as
aluminum (A13+). Salts of the Periodic Table's transient elements such as iron
(Fe2+ and Fe3+)
and zinc (Zn2 ) could also be effective subject to any case-specific
environmental considerations.
During or after treatment of bitumen-water or heavy-oil-water emulsions with
such salts to
destabilize the emulsion structure, the injection of air or any unreactive gas
such as but not
limited to nitrogen (N2), carbon dioxide (CO2), or flue gas composed primarily
of N2, CO2, and
unreacted oxygen (02) produced from steam generating boilers, will promote
separation of the
water and bitumen phases of the emulsions. Injection of an unreactive gas into
the emulsions
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promotes separation of bitumen or heavy oil from water, coalesces smaller
bitumen or heavy oil
droplets into larger droplets, and promotes the formation of bitumen-rich or
heavy-oil-rich froth,
which are important processes for efficient separation of bitumen or heavy oil
from water. As
used in this patent specification, the term "unreactive gas" refers to a gas
that in non-combustible
under process conditions.
Although several chemicals have been identified herein as being effective as
additives for
purposes of methods and processes in accordance with the present disclosure,
calcium oxide
(CaO, also known as lime) has been found to be particularly effective and
advantageous for
destabilization of bitumen-water or heavy-oil-water emulsions. CaO is a cost-
effective chemical
and is extensively used in the chemical industry. CaO is produced by thermal
decomposition of
calcite (CaCO3) by chemical reaction:
CaCO3 CaO + CO2
(Equation 1)
When bitumen-water or oil-water emulsions are treated with CaO, CaO becomes
calcium
hydroxide (Ca(OH)2) in aqueous environments by the following reaction:
CaO + H20 <---> Ca(OH)2 (Equation 2)
Also in aqueous environments, Ca(OH)2 dissociates to Ca2+ and 01-1- ions by
the
following reaction:
Ca(OH)2 Ca2++ 20H-
(Equation 3)
where the extent of the reaction favors towards Ca(OH)2 as temperature
increases, which must be
taken into consideration in the selection of the retention time for the design
of process vessels in
which bitumen-water or heavy-oil-water emulsions are to be treated with CaO.
Addition of CaO
into such emulsions reduces the activity of water-soluble naphthenic or
asphaltic acids (denoted
by the formula HA, in which A- represents the anionic naphthenic and asphaltic
acid group acting
as surfactant, and H+ is the acidic proton) and naphthenic or asphaltic acid
salts such as sodium
salts (NaA) by precipitating them in the form of water-insoluble calcium
naphthenates or
asphaltates (CaA2) in accordance with the following reactions:
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2HA + Ca(OH)2 CaA2 + 2H20
(Equation 4)
2NaA + Ca(OH)2 CaA2 + 2NaOH
(Equation 5)
The use of CaO as a process additive for destabilization of bitumen-water or
heavy-oil-
water emulsions provides advantages of improved water chemistry by reducing
bicarbonate
hardness of the recovered water in accordance with the following reaction:
Ca(HCO3)2 + Ca(OH)2 2CaCO3 + 2H20
(Equation 6)
The use of CaO (which becomes Ca(OH)2 in aqueous environments) as a process
additive
for destabilization of bitumen-water or heavy-oil-water emulsions also
promotes the
advantageous result of flocculating water-wet sodium clay (Clay-Na) dispersed
in water by the
following ion exchange reaction:
Clay-Na + Ca(OH)2 (Clay)2 + 2NaOH
(Equation 7)
by which the water-wet sodium clay, which easily disperses in water, is
transformed into calcium
clay, which does not tend to associate with water. Eventually, the clay
particles flocculate as
calcium clay and are thus separated out from the emulsion.
Furthermore, any excess amount of Ca(OH)2 added into the emulsions would be
buffered
by carbon dioxide (CO2), including the CO2 present in the atmosphere, in
accordance with the
following reaction:
Ca(OH)2 + CO2 <---> CaCO3 + 2H20
(Equation 8)
However, excessive treatment of the emulsions or recovered water with CO2
would
promote the formation of water-soluble bicarbonates in accordance with the
following reaction:
CaCO3 + CO2 + H20 <---> Ca(HCO3)2
(Equation 9)
which may be disadvantageous for purposes of recycling of recovered water to
bitumen or oil
production plants. Therefore, it will be prudent to monitor the pH of the
emulsion and the
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recovered water when treating bitumen-water or heavy-oil-water emulsions
and/or recovered
water with CO2; more specifically, it will be desirable to monitor the pH and
water chemistry.
Laboratory Testing
In laboratory tests conducted by the inventors, two bitumen-water emulsions
produced by
a SAGD process were analyzed using the Dean-Stark extraction apparatus. It was
observed that
one of these emulsions contained about 14% bitumen and the other emulsion
contained about
28% bitumen; both emulsions contained about 0.3% fines, with the remainder of
both emulsions
being water. Analyses of bitumen samples recovered from these emulsions showed
that the
bitumen in both samples comprised about 19% saturates, 46% aromatics, 15%
resins, and 20%
asphaltenes (all on mass basis). The chemistry of the water recovered from the
test emulsions by
centrifugation (for example, without adding any chemical additive) is
presented in Table 1.
Table 1 - Chemical analysis of the water recovered from bitumen-water emulsion
Hc03- Mg" Ca" Na+ K+
NH4+ Cr S 042-
pH (mg CaCO3/L) (mg/L) (mg/L)
(mg/L) (mg/L) (mg/L) (mg/L) (mg/L)
8.14 166 0.2 1 402 15 8.5 448 5
The high alkalinity (i.e., pH = 8.14) indicated in Table 1 appears to be
caused by
bicarbonate species from the reservoir rock. Because of the alkaline nature of
the process water,
the naphthenic and asphaltic acids present in bitumen or heavy oil (more
specifically in the
asphaltenes fraction) become water soluble and act as surfactants reducing the
interfacial tension
between bitumen and water and thereby promoting stability of the bitumen-water
emulsion. The
test emulsions most likely formed during the flow of immiscible bitumen and
water through the
reservoir sand matrix under the pressure drop created by gravity and applied
pressure difference
between the SAGD steam injection and production wells. If the emulsion
formation was caused
by surfactant behavior of the naphthenic and asphaltic acids present in
bitumen asphaltenes, then:
(1)
reducing pH of the emulsion (for example, by addition of hydrochloric acid -
HC1)
should destabilize the emulsion by shifting the equilibrium of HA4-+A-+H+
towards
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HA (HA being the naphthenic or asphaltic acid; A" being the anionic naphthenic
and
asphaltic acid group acting as surfactant; and H+ being the acidic proton);
(2) increasing the pH of the emulsion (for example, by addition of sodium
hydroxide
(NaOH) or a mild basic salt such as sodium bicarbonate (NaHCO3)) should
further
stabilize the emulsion or not affect the stability of the emulsion;
(3) increasing Ca2 concentration (for example, by addition of calcium
chloride (CaCl2))
should destabilize the emulsion in accordance with the reaction 2A-+Ca2+4¨*
CaA2,
thereby reducing the activity of A" functional groups that act as surfactants;
and
(4) increasing Ca2+ concentration (for example, by addition of CaO (lime))
should
destabilize the emulsion by the same reason explained in point (3) immediately
above.
Emulsion destabilization experiments performed using HC1, NaHCO3, CaC12, and
CaO
(Ca(OH)2 in aqueous systems) as additives corroborated the four theses
presented above: the
addition of CaO, CaC12, and HC1 all destabilized the emulsions, while the
addition of NaOH and
NaHCO3 appeared to increase emulsion stability.
The present disclosure has focused on the use of CaO as a process additive,
since CaO has
been found to have the capacity to improve process water chemistry, to
precipitate naphthenates
and asphaltates, and to promote flocculation of clay particles by the chemical
reactions expressed
in Equations (4), (5), (6) and (7).
The most effective dosages of CaO for methods and processes in accordance with
the
present disclosure appear to be in the range of about 2.5 to about 3.0 grams
of CaO per kilogram
of emulsion. However, the dosage of CaO addition could be adjusted for the
specific needs of
the process applications. Depending on the chemical characteristics of a
particular emulsion
(including considerations such as bicarbonate content and p11), an appropriate
and effective CaO
dosage could be in the range between about 50 milligrams to about 5.0 grams
per kilogram of
emulsion. Injection of an inert gas such as nitrogen (N2) or other unreactive
gas reduces the time
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required for the destabilization of the emulsion and recovery of bitumen or
oil and water as
separate streams.
Laboratory tests showed that methods and processes in accordance with the
present
disclosure work better as process temperature increases. This may be
particularly advantageous
in the context of field operations where emulsions are produced at elevated
temperatures and
pressures depending on the reservoir characteristics. Bitumen-water emulsions
produced in
SAGD processes will typically be at a temperature of about 210 C. (410 F.)
and at pressure of
about 1.6 megaPascals (220 psia). Accordingly, methods and processes in
accordance with the
present disclosure could be applied with high-temperature bitumen-water
emulsions.
In this patent document, any form of the word "comprise" is to be understood
in its
non-limiting sense to mean that any item following such word is included, but
items not
specifically mentioned are not excluded. A reference to an element by the
indefinite article "a"
does not exclude the possibility that more than one of the element is present,
unless the context
clearly requires that there be one and only one such element. Wherever used in
this document,
the terms "typical" and "typically" are to be interpreted in the sense of
representative or common
usage or practice, and are not to be understood as implying invariability or
essentiality.
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