Note: Descriptions are shown in the official language in which they were submitted.
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A PROCESS AND SYSTEM FOR ENHANCED SEPARATION OF
HYDROCARBON EMULSIONS
FIELD OF THE INVENTION
The present invention relates generally to hydrocarbon recovery, and
particularly
to improving hydrocarbon recovery by enhancing separation of hydrocarbon-
comprising emulsions.
BACKGROUND OF THE INVENTION
Hydrocarbon resources present significant technical and economic recovery
challenges due to formation of emulsions during recovery and processing. The
resultant emulsions may be, for example, oil-in-water, water-in-oil phase
configurations or a combination thereof. The emulsions can be complex, and
may include solids (e.g., fines), organic and inorganic species, and emulsion
stabilizing species. Also, to the extent that gases may be among the produced
hydrocarbons, some emulsions may also include a gas phase.
To maximize oil production and to also maximize the volume of clean water
which may be either disposed of or recycled, it is important to effectively
separate
or "break" the emulsions. A number of approaches to breaking emulsions have
been recognized within the industry, examples of which include the use of
chemicals (e.g., altering surface tension characteristics), thermal techniques
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(e.g., modulating heat), mechanical techniques (e.g., modulating residence
time),
and electrical techniques (e.g., providing electrostatic grids).
Although the present approaches facilitate some degree of resolution of the
emulsions, there continues to be a need for more effective and economically
feasible emulsion breaking techniques to improve the economical performance of
hydrocarbon recovery, improve process robustness and stability, and provide an
economical method of debottlenecking existing facilities.
SUMMARY OF THE INVENTION
The present invention according to an embodiment provides a process for
enhanced separation of a hydrocarbon-comprising emulsion. The system
involves contacting the hydrocarbon-comprising emulsion with an aqueous
component at a first selected location in a hydrocarbon processing circuit to
control an occurrence of a high viscosity event in the hydrocarbon-comprising
emulsion. The process further involves dispersing the aqueous component within
the hydrocarbon-comprising emulsion under low shear conditions so as to
destabilize the hydrocarbon-comprising emulsion and initiate coalescence of
like
phases to form an aqueous component-treated emulsion, wherein the aqueous
component-treated emulsion has an increased water cut and a reduced viscosity
as compared to a water cut and a viscosity of the hydrocarbon-comprising
emulsion, the aqueous component-treated emulsion being sufficiently stable to
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pass through one or more processing units downstream of the first selected
location without passing through the high viscosity event while being
sufficiently
unstable to break down into hydrocarbon and aqueous constituents at a second
selected location in the hydrocarbon processing circuit downstream of the one
or
more processing units.
The present invention according to another embodiment provides a system for
enhanced separation of a hydrocarbon-comprising emulsion. The system
includes means for contacting the hydrocarbon-comprising emulsion with an
aqueous component at a first selected location in a hydrocarbon processing
circuit to control an occurrence of a high viscosity event in the hydrocarbon-
comprising emulsion. The system further includes means for dispersing the
aqueous component within the hydrocarbon-comprising emulsion under low
shear conditions so as to destabilize the hydrocarbon-comprising emulsion and
initiate coalescence of like phases to form an aqueous component-treated
emulsion, wherein the aqueous component-treated emulsion has an increased
water cut and a reduced viscosity as compared to a water cut and a viscosity
of
the hydrocarbon-comprising emulsion, the aqueous component-treated emulsion
being sufficiently stable to pass through one or more processing units
downstream of the first selected location without passing through the high
viscosity event while being sufficiently unstable to break down into
hydrocarbon
and aqueous constituents at a second selected location in the hydrocarbon
processing circuit downstream of the one or more processing units.
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The present invention according to a further embodiment provides a process for
enhanced separation of a hydrocarbon-comprising emulsion. The process
involves contacting the hydrocarbon-comprising emulsion with an aqueous
component upstream of a degasser. The process further includes dispersing the
aqueous component within the hydrocarbon-comprising emulsion under low
shear conditions so as to destabilize the hydrocarbon-comprising emulsion and
initiate coalescence of like phases to form an aqueous component-treated
emulsion, wherein the aqueous component-treated emulsion has an increased
water cut and a reduced viscosity as compared to a water cut and a viscosity
of
the hydrocarbon-comprising emulsion, the aqueous component-treated emulsion
being sufficiently stable to pass through the degasser without passing through
an
emulsion inversion region while being sufficiently unstable to break down into
hydrocarbon and aqueous constituents during separation downstream of the
degasser.
In various embodiments, the hydrocarbon-comprising emulsion may be derived
from an in situ thermal process or crude oil operations, and the in situ
thermal
process may be steam assisted gravity drainage (SAGD), expanding solvent-
steam assisted gravity drainage (ES-SAGD), cyclic steam simulation (CSS),
steam flooding (SF), solvent assisted-cyclic steam simulation, toe-to-heel-air-
injection (THAI), or solvent aided process (SAP).
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In various embodiments, the hydrocarbon-comprising emulsion is a chemically
complex heterogeneous tight emulsion which may comprise bitumen and
asphaltenes. In various embodiments, the chemically complex heterogeneous
tight emulsion comprises a water-in-oil-in-water phase configuration, which
may
comprise highly sheared droplets (e.g., ranging in size from about 1 m to
about
100 .Lm, about 1 to 50 m) and entrained gas.
In various embodiments, the water cut of the hydrocarbon-comprising emulsion
is
generally within the emulsion inversion region of the hydrocarbon-comprising
emulsion. In further embodiments, the increased water cut of the aqueous
component-treated emulsion is such that a water-continuous phase is
substantially the only phase in the aqueous component-treated emulsion.
In various embodiments, the aqueous component comprises water or is water
such as for example, fresh water, process derived water or a combination
thereof. In various embodiments, the water may have low salinity.
In various embodiments, the contacting of the aqueous component with the
hydrocarbon-comprising emulsion may involve adding the aqueous component to
the hydrocarbon-comprising emulsion in pipe or in a vessel, and the adding may
be effected effected using a co-current flow, a counter-current flow, a co-
current
central flow, or a counter-current central flow. In various embodiments, the
aqueous component may be a continuous stream or a spray. In various
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embodiments, in which contacting is performed upstream of a degasser, the
contacting is performed generally in an immediate proximity to the degasser.
In various embodiments, dispersing of the aqueous component may involve a
use of a low shear mixer. In further embodiments, separation downstream of the
degasser may involve separation in a gravity separator such as a free water
knock out unit (FWKO). In various embodiments, break down into hydrocarbon
and aqueous constituents of the aqueous component-treated emulsion results in
a generally distinct hydrocarbon phase and a generally distinct aqueous phase.
In various embodiments, the process further involves adding a processing aid
to
the aqueous component-treated emulsion such as for example a diluent, a
chemical or a combination thereof.
In various embodiments, the process may further involve degassing the aqueous
component-treated emulsion in the degasser to form a degassed aqueous
component-treated emulsion, and the degassed aqueous component-treated
emulsion may be passed through a heat exchanger to produce a cooled
degassed aqueous component-treated emulsion. The cooled degassed aqueous
component-treated emulsion may be further processed in the gravity separator
to
result a reduced rag layer as compared to a rag layer produced from separating
the hydrocarbon-comprising emulsion. In various embodiments, the reduced rag
layer, a remaining aqueous component-treated emulsion, or both the reduced rag
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layer and the remaining aqueous component-treated emulsion may be further
treated in a treater.
In various embodiments, the process for enhanced separation of a hydrocarbon-
comprising emulsion may involve contacting the hydrocarbon-comprising
emulsion with an aqueous component upstream of a heat exchanger, and
dispersing the aqueous component within the hydrocarbon-comprising emulsion
under low shear conditions so as to destabilize the hydrocarbon-comprising
emulsion and initiate coalescence of like phases to form an aqueous component-
treated emulsion, wherein the aqueous component-treated emulsion has an
increased water cut and a reduced viscosity as compared to a water cut and a
viscosity of the hydrocarbon-comprising emulsion, the aqueous component-
treated emulsion being sufficiently stable to pass through the heat exchanger
without passing through an emulsion inversion region while being sufficiently
unstable to break down into hydrocarbon and aqueous constituents during
separation downstream of the heat exchanger.
In yet further embodiments, the process for enhanced separation of a
hydrocarbon-comprising emulsion may involve contacting the hydrocarbon-
comprising emulsion with an aqueous component upstream of a separator, and
dispersing the aqueous component within the hydrocarbon-comprising emulsion
under low shear conditions so as to destabilize the hydrocarbon-comprising
emulsion and initiate coalescence of like phases to form an aqueous component-
treated emulsion, wherein the aqueous component-treated emulsion has an
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increased water cut and a reduced viscosity as compared to a water cut and a
viscosity of the hydrocarbon-comprising emulsion, the aqueous component-
treated emulsion being sufficiently stable to pass into the separator without
passing through an emulsion inversion region while being sufficiently unstable
to
break down into hydrocarbon and aqueous constituents during separation in the
separator.
BRIEF DESCRIPTION OF THE DRAWINGS
In accompanying drawings which illustrate embodiments of the invention, by way
of
example only,
Fig. I illustrates a schematic diagram of the process according to the various
embodiments;
FIG. 2 illustrates emulsion viscosity as a function of water content, and the
inversion point or region of the emulsion;
FIG. 3 illustrates factors which may influence the occurrence of the emulsion
inversion point or region, limited to show water and chemical for instructive
purposes;
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FIG. 4 illustrates the effects of chemical injection and addition of the
aqueous
component (e.g., water recycle) on the occurrence of the inversion point or
region;
FIG. 5 illustrates a system for contacting the aqueous component with the
hydrocarbon-comprising emulsion upstream of an inlet degasser according to an
embodiment;
FIG. 6 illustrates a system for contacting of the aqueous component with the
hydrocarbon-comprising emulsion upstream of a heat exchanger according to an
embodiment;
FIG. 7 illustrates a system for contacting of the aqueous component with the
hydrocarbon-comprising emulsion upstream of a free water knockout unit (FWKO
according to an embodiment);
FIG. 8 illustrates a system for contacting of the aqueous component with an
emulsion derived from the hydrocarbon-comprising emulsion upstream of a
treater according to an embodiment;
FIG. 9 illustrates co-current contacting of the aqueous component with the
hydrocarbon-comprising emulsion in a vessel (e.g., in pipe) according to an
embodiment;
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FIG. 10 illustrates counter-current contacting of the aqueous component with
the
hydrocarbon-comprising emulsion in a vessel (e.g., in pipe) according to an
embodiment;
FIG. 11A illustrates co-current central contacting of the aqueous component
with
the hydrocarbon-comprising emulsion in a vessel (e.g., in pipe) according to
an
embodiment;
FIG. 11 B illustrates counter-current central contacting of the aqueous
component
with the hydrocarbon-comprising emulsion in a vessel (e.g., in pipe) according
to
an embodiment;
FIG. 12 illustrates principles of operation of the free water knockout unit
(FWKO)
and examples of various separation profiles that may result;
Fig. 13 illustrates a schematic diagram of a Steam Assisted Gravity Drainage
(SAGD) process and production of the hydrocarbon comprising emulsion
according to an embodiment;
FIG. 14 illustrates a schematic diagram of a process circuit for treating the
hydrocarbon-comprising emulsion according to prior art;
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FIG. 15 illustrates data relating to increases in pressure drop across the
heat
exchangers;
FIG. 16 illustrates data relating to a typical elevated pressure drop event
including the duration and magnitude of the event;
FIG. 17 illustrates recycle flow rates obtained in a FWKO trial;
FIG. 18 illustrates a heat exchanger low pressure drop histogram;
FIG. 19 illustrates a heat exchanger high pressure drop histogram;
FIG. 20 illustrates data relating to calculated BSW to FWKOs and heat
exchanger pressure drop;
FIG. 21 illustrates further data relating to calculated BSW to FWKOs and heat
exchanger pressure drop;
FIG. 22 illustrates recycle flow rates obtained in the inlet degasser trial;
FIG. 23 illustrates a schematic depicting good vs. poor resolution of
emulsions;
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FIG. 24 illustrates a schematic of a larger unresolved emulsion layer
indicative of
poor separation;
FIG. 25 illustrates a schematic of a smaller unresolved emulsion layer
indicative
of good separation;
FIG. 26 illustrates data relating to produced water recycle to the FWKO;
FIG. 27 illustrates further data relating to produced water recycle to the
FWKO;
FIG. 28 illustrates data relating to effects of water cut on pressure drop and
separation;
FIG. 29 illustrates increased separation achieved with the treatment of the
hydrocarbon-comprising emulsion with the aqueous component (water recycle);
and
FIG. 30 illustrates increased gas removal achieved with the treatment of the
hydrocarbon-comprising emulsion with the aqueous component (water recycle).
DETAILED DESCRIPTION
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Reference will now be made in detail to implementations and embodiments of
various aspects and variations to the invention, examples of which are
illustrated
in the accompanying drawings.
According to an embodiment as is schematically illustrated in Figure 1, the
process and system of the present invention relate to improving recovery of a
hydrocarbon from a hydrocarbon-comprising emulsion by treating the
hydrocarbon-comprising emulsion with an aqueous component to form an
aqueous component-treated emulsion, and subsequently processing the
aqueous component-treated emulsion to recover the hydrocarbon. In various
embodiments, the aqueous component is selected and contacted with the
hydrocarbon-comprising emulsion in a manner and proportion so as to promote
coalescence of the like phases while minimizing shear, which results in a
decreased viscosity of the emulsion and a shift away from the emulsion
inversion
point or region toward a water-continuous state.
In various embodiments of the invention, the term "hydrocarbon" is used
interchangeably with "oil". In various embodiments, the terms "hydrocarbon" or
"oil" refer to any natural or synthetic liquid, semi-liquid or solid
hydrocarbon
material derived from oil and gas operations including crude oil operations in
situ
and ex situ, oil sands processing in situ and ex situ, biofuel operations, or
any
other industry in which it is necessary to recover the hydrocarbon from a
hydrocarbon-comprising emulsion. The hydrocarbon in various embodiments
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includes, for example, hydrocarbon material having an API value of less than
about 100, heavy oil production (e.g., about 10 to about 22.3 API), medium
oil
production (e.g., about 22.3 to about 31.1 API), light oil production (e.g.,
> about
31.1 API), off shore oil production, natural gas operations, conventional
oil,
secondary and tertiary recovery, or biofuel. For example, in particular
embodiments, the hydrocarbon may be "heavy oil", "extra heavy oil", or
"bitumen"
which refer to hydrocarbons occurring in semi-solid or solid form having a
viscosity in the range of about 100,000 to over 1,000,000 cP measured at
original in situ deposit temperature. In this specification, the terms
"hydrocarbon",
"heavy oil", "oil" and "bitumen" are used interchangeably. Depending on the in
situ density and viscosity of the hydrocarbon, the hydrocarbon may comprise,
for
example, a combination of heavy oil, extra heavy oil and bitumen. Heavy crude
oil, for example, may be defined as any liquid petroleum hydrocarbon having an
API gravity less than about 20 , specific gravity greater than about 0.933
(g/ml),
and viscosity greater than 100 cP. Oil may be defined, for example, as a
hydrocarbon mobile at typical reservoir conditions. Extra heavy oil, for
example,
may be defined as having a viscosity of over 100,000 cP and about 10 API
gravity. The API gravity of bitumen ranges from about 12 API to about 7 and
the viscosity is greater than about 100,000,000 cP. In various embodiments
where the hydrocarbon is derived from in situ oil sands operations, such
operations include any in situ operation, including steam-based operations,
solvent-based operations, oxidation/combustion-based operations or a
combination thereof. Examples of such in situ thermal operations include Steam
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Assisted Gravity Drainage (SAGD), Expanding Solvent-SAGD (ES-SAGD),
Cyclic Steam Stimulation (CSS), Steam Flooding (SF), Solvent-Assisted CSS
(LASER), Toe-to-Heel-Air-Injection (THAI), or Solvent Aided Process (SAP).
In various embodiments of the invention, the term "hydrocarbon-comprising
emulsion" refers to a heterogeneous mixture of two substantially immiscible
liquid
or semi-liquid phases wherein, for example, one phase is dispersed as small
droplets in the second phase and where the droplets of the first phase have a
reduced tendency to coalesce or collide with each other such that the two
phases
do not spontaneously separate. In various embodiments, one phase of the
hydrocarbon-comprising emulsion comprises the hydrocarbon and the other
phase comprises water. In various embodiments, the hydrocarbon, water
(aqueous phase) or both may further comprise various contents of other
chemical species such as, for example, various contents of gases (e.g.,
hydrogen sulfide), organosulfur and inorganic sulfur compounds, various salts,
salt-forming species, organometallic and inorganic species, surfactants,
surfactant precursors, solids (e.g., fines such as clays, sand particles),
diluents or
processing additives, or a combination thereof. These chemical species may be
present as dissolved, dispersed or bound within the hydrocarbon, water or
both.
The presence of such chemical species can contribute to the chemical
complexity of the hydrocarbon-comprising emulsion (e.g., heterogeneity of the
emulsion) as such species can stabilize the emulsion making it difficult to
break
in order to recover the hydrocarbon. In various embodiments, heterogeneity of
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the hydrocarbon-comprising emulsion may arise not only from the source of the
hydrocarbon but also from any processing techniques the emulsion is subjected
to prior to the treatment with the aqueous component according to the various
embodiments of the invention.
In various embodiments, depending on the source of the hydrocarbon-comprising
emulsion, the chemical and physical makeup of the hydrocarbon-comprising
emulsion can continuously change. For example, in embodiments in which the
hydrocarbon emulsion is produced in situ from a bituminous reservoir, the
properties and porosity of which may be variable, in combination with the
manner
in which the hydrocarbon-comprising emulsion is generated in situ, the
emulsion
may have variable properties. For example, the hydrocarbon-comprising
emulsion produced by a Steam Assisted Gravity Drainage (SAGD) process is
typically a chemically complex and "tight" emulsion as compared to a crude oil
emulsion which is generally considered to be a "loose" emulsion. A SAGD-
derived emulsion is typically a water-in-oil-in-water emulsion, although other
emulsion types may also be present. Such an emulsion consists of extremely
small water droplets emulsified in larger oil droplets in a water continuous
external phase. The hydrocarbon-comprising emulsion produced from a thermal
in situ process such as SAGD can also comprise a high asphaltene content, and
thus be stabilized by such species. During production, the emulsion is
subjected
to high shear forces (e.g., through reservoir steaming, contacting with well
bore
liners, electrical submersible pumps, gas lift or a combination thereof) and
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mixing, which result in "tight" difficult to break emulsions. For example, the
hydrocarbon-comprising emulsion derived from SAGD typically comprises highly
sheared droplets ranging in size from about 1 m to about 100 pm, from about 1
m to about 50 m. The hydrocarbon-containing emulsion derived from in situ
operations such as, for example, SAGD may further comprise gas from the
reservoir entrained in the emulsion, sand, clays and other chemical species
(e.g.,
natural or added surfactants). The manner in which the hydrocarbon-comprising
emulsion, such as a SAGD emulsion, is produced (e.g., exposure to high shear,
high temperatures and pressures (e.g., about 130 C to about 200 C and about
1000 kPag to 2000 kPag) and pH (e.g., about 6.5 to about 10, about 6.5 to
about
7) contribute to creating a difficult to break emulsion. This is in contrast
to
hydrocarbon-comprising emulsions that may result from crude oil operations.
Crude oil emulsions are generally simple "loose" emulsions (e.g., oil-in-water
or
water-in-oil) which are less difficult to break. In various embodiments,
addition of
an aqueous component can still be beneficial for processing of "loose"
emulsions. In particular embodiments where the hydrocarbon-comprising
emulsion is derived from in situ operations such as SAGD, the heterogeneous
nature of the emulsion further arises because the emulsion is typically a
combination of emulsions from various SAGD wells from various well pads that
may be located in different regions of the bituminous reservoir, produced from
wells at different stages of SAGD operations, or a combination thereof. The
produced emulsions, having highly variable chemical and physical properties,
may be further affected by pipeline transport conditions. For example, the
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hydrocarbon-comprising emulsion derived from SAGD can vary in composition
and properties both laterally along the length of the pipeline and through any
given cross section (e.g., comprise slugs of high viscosity inverted
emulsions).
In various embodiments, the hydrocarbon-comprising emulsion and the aqueous
component-treated emulsion are described as having a "water cut". In various
embodiments, the term "water cut" refers to a fraction of water in the
hydrocarbon-comprising emulsion or the aqueous component-treated emulsion
relative to the total volume of the hydrocarbon-comprising emulsion or the
total
volume of the aqueous component-treated emulsion. In various embodiments,
the water cut of the hydrocarbon-comprising emulsion will vary depending on
the
source of the emulsion. In various embodiments, the hydrocarbon-comprising
emulsion is an emulsion that has not been dewatered prior to treatment with
the
aqueous component so as to reduce the content of water relative to the content
of the hydrocarbon (i.e., water cut). In various embodiments, the hydrocarbon-
comprising emulsion refers to a bulk emulsion rather than a localized emulsion
layer (e.g., a rag layer) formed during a separation process. In various
embodiments, the aqueous component addition can also be used to treat rag
layer. For example, in various embodiments, the rag layer may be
preferentially
treated by recycling upstream of the aqueous component addition in order to
subject the rag layer to treatment with the aqueous component (e.g., recycle
water) along with the bulk emulsion. In various other embodiments, the rag
layer
can also be slipstreamed with an aqueous component added into the rag stream,
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prior to being recycled back to a FWKO or treater, depending on what is
practical
or economically feasible for the process and facility design. In particular
embodiments, for example, the rag-layer, the aqueous component-treated
emulsion which has been reduced or minimized by the treatment with the
aqueous component (i.e., remaining or residual aqueous component-treated
emulsion) or both may be processed in, for example, a separator such as FWKO,
a treater or both. In various embodiments, the process and system of the
present
invention may also be applied to an intermediate hydrocarbon-comprising
emulsion, or an intermediate aqueous component-treated emulsion which have
been previously pretreated to some extent at various stages of the hydrocarbon
recovery. Pretreatment may include physical and chemical treatments such as,
for example, initial separation or fractionation, including separation of
solids,
addition of a diluent, or cooling. In various embodiments, the addition of the
diluent is preferably performed following the contacting of the hydrocarbon-
comprising emulsion with the aqueous component because the diluent is more
effectively dispersed within the resultant aqueous component-treated emulsion
as compared to the hydrocarbon-comprising emulsion as a result of the
treatment with the aqueous component.
One aspect associated with the water cut of the hydrocarbon-comprising
emulsion or the aqueous component-treated emulsion is an emulsion inversion
point or region. The emulsion inversion point or region relates to the water
cut of
the emulsion at or in the vicinity of which the emulsion can invert (i.e., the
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disperse phase becomes the continuous phase and vice versa) (e.g., Figure 2).
Furthermore, the water cut and the inversion point or region are related to a
viscosity of the emulsion and may be modulated by a number of factors,
including diluent or chemical addition, addition of the aqueous component
(e.g.,
water) or a combination thereof as is illustrated for example in Figures 3 and
4.
There can be a significant increase in the viscosity of the bulk hydrocarbon-
comprising emulsion at the point or region of inversion of the continuous
phase.
In various embodiments, the water cut of the hydrocarbon-comprising emulsion
will vary depending on the source of the emulsion and complexity. For example,
the hydrocarbon-comprising emulsion produced from an in situ thermal process
such as SAGD (e.g., a water-in-oil-in-water emulsion) may have a water cut of
about 40% to about 85% water which is very close to the inversion point or
region of this emulsion.
Figure 3 illustrates
1) operating on the edge of inversion point or region, with oil cut
occasionally
increasing to the point that operations are on the higher point of viscosity
curve;
2) with chemical and diluent injection, the inversion curve was shifted - now
operating on a lower part of the curve consistently with less opportunity to
cross inversion point or region;
3) with water recycle (i.e., the aqueous agent), operations can move further
down the viscosity curve to achieve similar results; and
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4) because of the complexity of the hydrocarbon-comprising emulsion, the
characteristics of the viscosity curve and where the inversion point or
region lies for such a complex heterogeneous emulsion, and many other
contributing factors, periodic sampling or dynamic monitoring of the
hydrocarbon-comprising emulsion may be needed in various
embodiments to test the extent to which operation can shift along the
curve to achieve the various advantages.
Figure 4 illustrates that a chemical processing aid rate, a diluent rate or
both can
be reduced to shift or alter the curve, with compensation for reduced chemical
or
diluent rates by aqueous component agent to ensure operation on the lower
viscosity region of the curve.
In various embodiments, factors which can influence the nature and behavior of
the hydrocarbon-comprising emulsion, and also the emulsion inversion point or
region include for example: relative quantities of the two components
(hydrocarbon and water), quantities of other chemical species (e.g., emulsion
stabilizers) in the hydrocarbon-comprising emulsion, ratio of viscosity of the
two
main components (hydrocarbon and water), shear history, solids content, pH,
oil
composition, droplet size distribution, flow regime through piping, hysteresis
of
the inversion point relationship, interfacial surface tension, temperature
change
or a combination thereof. As the relative quantity of the two main emulsion
constituents (i.e., hydrocarbon and water) varies, and also as the other
potential
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"triggers" change, the continuous phase may switch from one constituent to the
other (i.e., a switch from oil being the continuous phase to water being the
continuous phase or visa versa) and result in an increase in viscosity.
Hydrocarbon recovery operations in the vicinity of the region of the emulsion
inversion point or region can experience, for example, a reduction in facility
capacity (e.g., vessel residence time), hydraulic limitations (e.g., pressure
drop),
temporary exchanger fouling, significant difficulty in breaking the emulsion,
unpredictable and unstable process operation, poor water/hydrocarbon
separation, poor gas separation (e.g., for streams that include dissolved or
dispersed gases) or a combination thereof. In various embodiments, these
problems may be particularly prevalent in SAGD operations and SAGD-derived
emulsions with a lower steam-oil ratio (SOR), and hence lower water cut of the
hydrocarbon-comprising emulsion. In particular embodiments, the inversion
point or region for a SAGD-derived hydrocarbon-comprising emulsion may range,
for example, between about 15% to about 60% oil. The inversion point for a
complex emulsion such as a SAGD-derived emulsion is not fixed due to the
highly variable (time dependent) production profile from the various pads and
wells in the bituminous reservoir. For example, there may be wells at
different
stages of operation (e.g., new wells starting production, wedge wells
typically
producing lower water cuts), variability of hydrocarbon composition on a well
to
well basis or from the same well as time varies, effects of feeding the
hydrocarbon-comprising emulsion though a complex gathering system or a
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combination thereof resulting in a heterogeneous hydrocarbon-comprising
emulsion.
In various embodiments, the hydrocarbon-comprising emulsion to be treated with
the aqueous component according to the various embodiments of the invention
may have initial viscosities ranging from about 0.1 cP to about 100 cP. In
particular embodiments, a SAGD-derived hydrocarbon-comprising emulsion may
have initial viscosities ranging from about 0.1 cP to about 1000 cP.
In particular embodiments in which the hydrocarbon-comprising emulsion is
derived from SAGD operations, the hydrocarbon-comprising emulsion may have a
temperature ranging from about 130 C to about 200 C.
In various embodiments, to determine how much of the aqueous component
should be contacted with the hydrocarbon-comprising emulsion, the
hydrocarbon-comprising emulsion may be monitored by obtaining samples of the
emulsion according to a selected schedule for analysis, or by dynamically
monitoring and analysing the emulsion (e.g., in real time). In various
embodiments, the hydrocarbon and water content of the hydrocarbon-comprising
emulsion may be measured at selected locations within the processing circuit
(e.g., inlet to the degasser, inlet to the separator). In various embodiments,
an
excess of the aqueous component may be contacted with the hydrocarbon-
comprising emulsion. In such embodiments, a maximum overcompensatory
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amount of the aqueous component may be determined for treating the particular
hydrocarbon-comprising emulsion such that downstream operations are not
negatively impacted (e.g., downstream separators such as FWKOs).
In this specification, the term "aqueous component" refers a water-comprising
or
water-based component. In various embodiments, the aqueous component has
some salinity but it is not saturated (e.g., < about 1000 ppm). Because the
aqueous component has a relatively low salinity, its effect on the hydrocarbon-
comprising emulsion is not dependent on modulating the water density
(differential density between water and the hydrocarbon phase) in the
hydrocarbon-comprising emulsion to encourage the water to drop out of the
emulsion to achieve separation. In various embodiments, the aqueous
component is generally compatible with the hydrocarbon-comprising emulsion
(i.e., addition of which does not make the hydrocarbon-comprising emulsion
tighter). In various embodiments, the aqueous component is water. In this
specification, the term "water" is used interchangeably with the term "aqueous
component", and may comprise other dissolved or dispersed species, may be
derived from a fresh water source or from produced water (e.g., recycled
process
water).
In various embodiments, the aqueous component (e.g., water) may be derived
from a single source or a variety of water sources in combination. For
example,
in various embodiments, the aqueous component may be derived from, for
CA 02747886 2011-07-29
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example, a primary water separation stage (or as close to this point as
practically
possible) to ensure compatibility (e.g., not making the emulsion tighter) with
the
hydrocarbon-comprising emulsion and to improve water use efficiency.
Additional
benefits of using recycled water from, for example, the primary water
separation
stage relates to the benefit of recycling unused chemicals which have remained
in the water, the water having a suitable temperature or a combination
thereof. In
various embodiments, the composition of the aqueous component may be
modulated for treating a particular hydrocarbon-comprising emulsion to
efficiently
achieve the target aqueous component-treated emulsion (for example by addition
of chemical species such as demulsifies, modulating the temperature).
In various embodiments, the aqueous component may have any suitable
temperature so long as suitable contacting with the hydrocarbon-comprising
emulsion may be achieved and desired properties of the aqueous component-
treated emulsion may be achieved, namely a balance between a sufficient
stability
to pass through the degasser, the heat exchanger or both as an emulsion
without
passing though an emulsion inversion point and sufficient instability to break
down
into the hydrocarbon and water constituents for separation downstream of the
heat
exchanger. Depending on the source, the aqueous component may have a
temperature ranging from about 50 C to about 190 C. In various embodiments,
the
lower temperature limit of the aqueous component is governed by the beneficial
effects of increased water cut and increased coalescence out weighing the
negative effects of cooling the aqueous component treated hydrocarbon-
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comprising emulsion. In various embodiments, the upper temperature limit is
generally governed by limiting the flashing to vapour phase of the aqueous
component as it is added to the hydrocarbon-comprising emulsion, flashing
aqueous component to vapour phase would cause shear on the hydrocarbon-
comprising emulsion.
In various embodiments, the amount of the aqueous component to be contacted
with the hydrocarbon-comprising emulsion can be tailored to the particular
composition and properties of the hydrocarbon-comprising emulsion. In various
embodiments, the amount of the aqueous component to be added is such that
the aqueous component-treated emulsion has a viscosity lower than a viscosity
of the hydrocarbon-comprising emulsion and is a substantially stable water-
continuous emulsion. In various embodiments, the aqueous component-treated
emulsion may comprise a content of the aqueous component such that a water
content in aqueous component-treated emulsion ranges from about 40% to about
95%. In particular embodimiments, for example in SAGD processes, the aqueous
component-treated emulsion may comprise a content of the aqueous component
such that a water content in aqueous component-treated emulsion ranges from
about 80% to 95%. In various embodiments, the content of the aqueous
component in the aqueous component-treated emulsion is such that the aqueous
component-treated emulsion is sufficiently stable to pass through a degasser,
a
heat exchanger, a combination of the degasser and the heat exchanger as an
emulsion without passing though an emulsion inversion point or region (e.g.,
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without inverting from, for example, an oil-in-water emulsion to a water-in-
oil
emulsion and thus increasing in viscosity) while being sufficiently unstable
to
break down into the hydrocarbon and aqueous constituents in downstream
processing (e.g., in a separator).
In various embodiments, the aqueous component may be contacted with the
hydrocarbon-comprising emulsion at various stages of the hydrocarbon recovery
process or at a combination of various stages for treating an intermediate
hydrocarbon-comprising emulsion or an intermediate aqueous component-treated
emulsion depending on the process requirements. As is illustrated in the
example
embodiments below, the process and method of the present invention allow to
control the occurrence of the high viscosity event (i.e., inversion of the
emulsion
at the emulsion inversion point or region) in a location of choice (e.g., a
location
where such change in the viscosity will not have a substantially negative
impact
on the processing circuit). In various embodiments, the contacting points in
the
particular processing circuit may be selected depending on the process and
what
diluent, chemical injection or other requirements there may be. The aqueous
component may be contacted with the hydrocarbon-comprising emulsion, the
intermediate hydrocarbon-comprising emulsion or the intermediate aqueous
component-treated emulsion at a single contact point or via a staged approach
where several contacting locations may be selected. In various embodiments,
addition of other process aids (e.g., diluent, chemical processing aids), if
required,
may also be performed at a single or multiple locations in the processing
circuit to
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obtain any synergistic effects that may arise from the addition of such
process
aids aside from the addition of the aqueous component. The embodiments below
present by way of example only various circuit configurations showing various
contacting points for the aqueous component and any process aids.
For example, in selected embodiments, contacting of the aqueous component
with the hydrocarbon-comprising emulsion (e.g., recycled water) upstream of a
degasser may be preferred. In this embodiment, maximum gas removal from the
aqueous component-treated emulsion may be realized in the inlet degasser, as
well as downstream benefits such as reduced pressure drop and improved heat
transfer across a heat exchanger, reduced separation problems in an emulsion
separator, treaters or a combination thereof, and enhanced dispersion of
chemical processing aid and diluent in the aqueous component-treated emulsion
(increased chemical / diluent efficiency). In various embodiments, a
demulsifier
may also be added upstream of the degasser to further aid in promoting
coalescence. An example of such an embodiment is illustrated in Figure 5.
As is shown in Figure 5, the hydrocarbon-comprising emulsion (1) is contacted
with the aqueous component (e.g. recycled water (3)) via a low shear water
contacting device (2). The resultant aqueous component-treated emulsion (4)
having an increased water cut as compared to the hydrocarbon-comprising
emulsion (1) is then optionally treated with chemicals (5) and fed through a
mixing device (6) to promote mixing and coalescence with as little shear as
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possible. This pre-conditioned aqueous component-treated emulsion (7) is then
fed to an inlet degasser (8) where gas is substantially removed (9). The
degassed aqueous component-treated emulsion (10) is then treated with diluent
or chemical (11) (optional) and directed to a heat exchanger (12) where it is
cooled to prevent the diluent light ends from flashing in the downstream
process
vessels. In various embodiments, the degassed aqueous component-treated
emulsion (10) may be cooled prior to the addition of the diluent. In the
various
embodiments, the emulsion may be cooled for several purposes including heat
recovery for efficient and economical operation of the plant, minimization of
water
vapor generation as the pressure is reduced through the process, minimization
of
the diluent that is flashed to vapour phase, and thus minimization of diluent
recovery equipment, or a combination thereof.
Figure 5 further shows that the cooled aqueous component-treated emulsion (13)
then flows to the next process vessel, such a for example a separator, the
Free
Water Knock Out unit (FWKO) (14). The FWKO unit is typically a large
horizontal
vessel which allows sufficient residence time to enable "free" coalesced water
in
the aqueous component-treated emulsion to separate by gravity from the
emulsion and be removed. The produced water (16) is removed from the bottom
of the vessel. The FWKO also allows any residual entrained gas (15) to evolve
from the emulsion and exit from the top of the vessel. If an unresolved
residual
emulsion (17) remains in the FWKO, it may be further treated with any
additional
diluent / chemicals (18) (optional) required and directed to a treater vessel
(19) to
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allow further residence time to separate into the main constituents of oil
(22) and
water (21). A common problem in a prior art process for treating the
hydrocarbon-comprising emulsion in the FWKO and the treater vessels is the
formation of an unresolved emulsion layer at the hydrocarbon/water interface
in
the vessel (i.e., a rag layer), which is difficult to treat and hinders
coalescence of
water and hydrocarbon droplets. The rag layer varies with the variability in
the
hydrocarbon-comprising emulsion. The rag layer may also hinder any further
evolution of gas bubbles. The treatment of the hydrocarbon-comprising emulsion
(i.e., bulk emulsion and not the rag layer itself) with the aqueous component
according to the various embodiments reduces or eliminates the problems
associated with the rag layer formation in the separator. Any further residual
gas
(20) evolved in the treater may exit from the top of the vessel. In various
embodiments, the treater may have a pressure of about 1100 kPag, and
therefore it is important to ensure that as much gas as possible is removed by
reducing viscosity and reducing or eliminating the rag layer to promote gas
liberation in the separator vessels. As is further shown in Figure 5, the
produced
water from the FWKO (16) and treater (21) may be collected into a common
header. A portion of this water may be then recycled back to the inlet to make
up
the water recycle (3) while the rest may be cooled and sent to a water
treatment
unit (not shown). The produced gas may be collected in a header and sent to
the
produced gas system (not shown). While in various embodiments, the
hydrocarbon-treated emulsion may contain solids, the solids may be separated
in
the inlet degasser, FWKO, the treater vessels or a combination thereof.
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In another embodiment, the aqueous component may be contacted with the
hydrocarbon-comprising emulsion, the intermediate hydrocarbon-comprising
emulsion, or the intermediate aqueous component-treated emulsion upstream of
the heat exchanger as is illustrated for example in Figure 6. In this
embodiment,
recycling water upstream of the heat exchanger will still prove beneficial,
but will
not address the problem of being unable to remove gas in the inlet degasser.
However, removal of gas may not be necessary in some embodiments where the
hydrocarbon-comprising emulsion does not contain substantial amounts of gas.
Even if some gas is present in the hydrocarbon-comprising emulsion, this gas
may be removed downstream, for example in the FWKO and the treater. In some
embodiments where the quantity of gas is not substantial, disruption of the
water-
oil interface in these separation vessels and hindering separation would not
be
significant. In embodiments, were the amount of gas in the hydrocarbon-
comprising emulsion is significant, the benefits seen in the heat exchanger,
namely a reduced pressure drop and a reduced fouling tendency, will still be
seen, as well as enhanced dispersion of diluent and chemicals even in the
absence of the addition of the aqueous component to the hydrocarbon-
comprising emulsion upstream of the degasser. Coalescence of water droplets
will also occur, allowing water to drop out in the FWKO and the treater. The
suitability of this embodiment could be tailored to the particular hydrocarbon-
comprising emulsion to be treated to determine the impact, if any, of the gas
in
the vessels on separation.
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In various embodiments, depending on the properties of the particular
hydrocarbon-comprising emulsion to be processed, reduction in fouling of the
heat exchanger is beneficial. For example, fouling may occur when the emulsion
is a viscous complex emulsion (e.g., comprising slugs of hydrocarbon). Such an
emulsion can coat the tubes of the heat exchanger resulting in restricted
flow,
reduced heat transfer and increased pressure drops. In various embodiments,
adding diluent upstream of the heat exchanger may help reduce fouling (e.g.,
wash or dissolve away the coating layer from the heat exchanger tubes).
Therefore in some embodiments, it may be beneficial to use diluent in addition
to
the aqueous component treatment. However, the process and system of the
present invention do not depend on the use of the diluent as addition of the
aqueous component addresses the problem of viscosity.
As is shown in Figure 6, the hydrocarbon-comprising emulsion (1) is directed
to
the inlet degasser (2) where gas is removed (3). The degassed hydrocarbon-
comprising emulsion (4) exits the inlet degasser and is contacted with the
aqueous component (e.g., recycled water (6)) injected via a low shear water
contacting device (5). The aqueous component-treated emulsion (7) increased in
water cut as compared to the hydrocarbon-comprising emulsion is treated with
chemicals and diluent (8) (optional) and fed through a mixing device (9) to
promote mixing and coalescence with as little shear as possible. This pre-
conditioned aqueous component-treated emulsion (10) is then fed to the heat
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exchanger (11). The emulsion is cooled to prevent the diluent light ends from
flashing in the downstream process vessels. The cooled aqueous component-
treated emulsion (12) then flows to the next process vessel such as the Free
Water Knock Out (FWKO) (13), which allows sufficient residence time to enable
"free" coalesced water to separate by gravity from the emulsion and be
removed.
The produced water (15) is removed from the bottom of the vessel. The FWKO
also allows any remaining entrained gas (14) to evolve from the aqueous
component-treated emulsion and exit from the top of the vessel. Any unresolved
residual emulsion (16) remaining in the FWKO is further treated with any
additional diluent / chemicals (17) (optional) required and flows to a treater
vessel
(18) to allow further residence time to separate into the main constituents of
oil
(21) and water (20). Any gas (19) evolved in the treater exits from the top of
the
vessel. Produced water from the FWKO (15) and treater (20) is collected into a
common header. A portion of this water can then recycled back to the inlet to
make up the water recycle (6) while the rest can be cooled and sent to water
treatment unit (not shown). The produced gas can be collected in a header and
sent to the produced gas system (not shown).
In various embodiments, the mixing device may or may not be required
depending on the specific properties of the hydrocarbon-comprising emulsion.
If
the mixing device is required, in various embodiments, the contact angle for
the
mixing device may be selected such that it is a water wet device. In various
embodiments, the material of construction for the mixing device may be
selected
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so that it has a suitable surface wettability as this aspect may affect the
phase
inversion point of the emulsion. An example of a suitable materials for the
mixing
device is stainless steel as it has lower contact angles (< about 900). In
various
embodiments, the orientation of the mixing device should also be
preferentially
oriented with it's longitudinal axis in the horizontal direction, which will
facilitate
minimizing the possibility of an unstable flow regime through the aqueous
component addition device and the low shear static mixer if present.
In yet another embodiment, the aqueous component may be contacted with the
hydrocarbon-comprising emulsion, the intermediate hydrocarbon-comprising
emulsion, or the intermediate aqueous component-treated emulsion upstream of
a separator (Figure 7). In this embodiment, contacting the aqueous component
(e.g., recycling water) upstream of the separator (e.g. FWKO) will continue to
prove beneficial, however it may not facilitate removal of gas in the inlet
degasser
or reduced pressure drop and fouling in the heat exchanger as effectively as
can
be observed with the other embodiments discussed where the aqueous
component is contacted with the hydrocarbon-comprising emulsion upstream of
the inlet degasser or upstream of the heat exchanger, or upstream of both.
Depending on the properties of the hydrocarbon-comprising emulsion to be
processed, removal of gas or reduced pressure drop aspects may not be at
issue. For example, if the hydrocarbon-comprising emulsion comprises a low
content of gas, the carryover of this gas downstream to the separator (e.g.
FWKO and treater) may not substantially affect the separation. In contrast in
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embodiments where the hydrocarbon-comprising emulsion comprises large
quantities of entrained gas, this embodiment may be as beneficial as some of
the
other described embodiments as the presence of gas may disrupt the water-oil
interface in these separation vessels and hinder separation. If the
hydrocarbon-
comprising emulsion to be processed is not very viscous, fouling of the heat
exchanger may not be an issue. In contrast if the hydrocarbon-comprising
emulsion has a high viscosity, this embodiment may not be preferred over the
other embodiments discussed because the viscous emulsion may coat the heat
exchanger tubes causing fouling, a reduction in heat transfer, as well as a
restricted flow area, and result in increased pressure drop. Although enhanced
dispersion of diluent and chemicals, as well as coalescence of water droplets
will
still occur in the case of a viscous hydrocarbon-comprising emulsion, process
performance may be hindered due to gas in the downstream separation vessels.
As is shown in Figure 7, the hydrocarbon-comprising emulsion (1) is fed to the
inlet degasser (2) where gas is removed (3). The degassed hydrocarbon-
comprising emulsion (4) exits the inlet degasser and diluent / chemicals are
optionally added (5). The hydrocarbon-comprising emulsion then flows through a
heat exchanger (6) where it is cooled to prevent the diluent light ends from
flashing in the downstream process vessels. The cooled hydrocarbon-comprising
emulsion (7) is then contacted with the aqueous component (e.g. recycled water
(9)) via a low shear water contacting device (8). The resultant aqueous
component-treated emulsion (10) having an increased water cut as compared to
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the hydrocarbon-comprising emulsion is treated with chemicals and diluent (11)
(optional) and fed through a mixing device (12) to promote mixing and
coalescence with as little shear as possible. This pre-conditioned aqueous
component-treated emulsion (13) is then fed to the next process vessel, which
may be a separator such as the Free Water Knock Out (FWKO) (14) which
allows sufficient residence time to enable "free" coalesced water to separate
by
gravity from the emulsion and be removed. The produced water (16) is removed
from the vessel. The FWKO also allows any remaining entrained gas (15) to
evolve from the emulsion and exit from the top of the vessel. The unresolved
residual emulsion (17), if any, remaining in the FWKO is further treated with
any
additional diluent / chemicals (18) (optional) required and flows to a treater
vessel
(19) to allow further residence time to separate into the main constituents of
oil
(22) and water (21). Any gas (20) evolved in the treater exits from the top of
the
vessel. Produced water from the FWKO (16) and treater (21) may be collected
into a common header. A portion of this water may be then recycled back to the
inlet to make up the water recycle (9) while the rest may be cooled and sent
to
water treatment unit (not shown). The produced gas is collected in a header
and
sent to the produced gas system (not shown).
In yet another embodiment, the aqueous component may be contacted with the
hydrocarbon-comprising emulsion upstream of the treater as is shown in Figure
8. This embodiment may be suitable for treating selected hydrocarbon-
comprising emulsions, intermediate hydrocarbon-comprising emulsions, or
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intermediate aqueous component-treated emulsions where there may be no
need to address problems relating to removal of gas (e.g., in the inlet
degasser),
reduction in pressure drop and fouling in the heat exchanger, separation and
coalescence in the FWKO or a combination thereof. According to this
embodiment, the contacting of the aqueous component with the hydrocarbon-
comprising emulsion, the intermediate hydrocarbon-comprising emulsion, or the
intermediate aqueous component-treated emulsion facilitates the dispersion of
diluent and chemical to the treater, and enhances separation in the treater by
promoting coalescence of water droplets. This embodiment may not be suitable
for treating the hydrocarbon-comprising emulsion, the intermediate hydrocarbon-
comprising emulsion, or the intermediate aqueous component-treated emulsion
comprising gas in quantities where process performance could be hindered due
to gas that has not been evolved upstream of the treater and has been carried
to
the treater because it may disrupt the water-oil interface.
As is illustrated in Figure 8, the hydrocarbon-comprising emulsion (1) is
collected
and fed to the inlet degasser (2) where gas is removed (3). The degassed
hydrocarbon-comprising emulsion (4) exits the inlet degasser and diluent /
chemicals may be added (5) (optional). The emulsion then flows through a heat
exchanger (6) where it is cooled to prevent the diluent light ends from
flashing in
the downstream process vessels. The cooled hydrocarbon-comprising emulsion
(7) is then fed to the next process vessel, such as for example, the Free
Water
Knock Out (FWKO) (8) to enable "free" coalesced water to separate by gravity
from the emulsion and be removed. The produced water (10) is removed from
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the bottom of the vessel. The FWKO also allows any remaining entrained gas (9)
to evolve from the emulsion and exit from the top of the vessel. The
hydrocarbon-
comprising emulsion (11) flows from the FWKO and is contacted with the
aqueous component (13) (e.g. recycled water) via a low shear water contacting
device (12). The aqueous component-treated emulsion (14) having an increased
water cut as compared to a water cut of the hydrocarbon-comprising emulsion is
treated with chemicals and diluent (15) (optional) and fed through a mixing
device (16) to promote mixing and coalescence with as little shear as
possible.
This pre-conditioned aqueous component-treated emulsion (17) is then fed to a
treater vessel (18) to allow further residence time to separate into the main
constituents of oil (21) and water (20). Any gas (19) evolved in the treater
exits
from the top of the vessel. Produced water from the FWKO (10) and treater (20)
may be collected into a common header. A portion of this water may be then
recycled back to the inlet to make up the water recycle (13) while the rest
may be
cooled and sent to water treatment unit (not shown). The produced gas may be
collected in a header and sent to the produced gas system (not shown).
In embodiments in which, for example, the hydrocarbon-comprising emulsion is
derived from an in situ process such as SAGD, the heat exchanger is typically
a
cooling heat exchanger. In such embodiments, the degasser is typically
operated
at higher than atmospheric pressure, which creates a different gas release
environment as compared to degassers operated at atmospheric pressure.
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In various embodiments, the aqueous component (e.g., water) is contacted with
the hydrocarbon-comprising emulsion so as to destabilize the emulsion and
initiate
coalescing of like phases prior to separation. Furthermore, the aqueous
component is contacted with the hydrocarbon-comprising emulsion so as to
increase bulk emulsion water cut and thus move the point of operation away
from
the emulsion inversion point into the water continuous region and to achieve a
sufficient dispersion of the aqueous component within the hydrocarbon-
comprising
emulsion to form the aqueous component-treated emulsion. In various
embodiments, the contacting of the aqueous component (e.g., water) is effected
in such a manner so as to not adversely shear the emulsion. When the
contacting is performed under low shear conditions, improved coalescence of
water drops to produce a more consistent/developed water continuous phase is
achieved. According to the various embodiments, the process and system of the
present invention facilitate imparting sufficient energy to allow or encourage
the
droplets in the hydrocarbon-comprising emulsion to collide and coalesce with
the
aqueous component without imposing additional shearing on the emulsion and
exacerbating the emulsion problem. Thus the process and system of the present
invention is related to modulation of the viscosity of the hydrocarbon-
comprising
emulsion by the addition of the aqueous component (and not by manipulation of
the temperature) and diameter of droplets during coalescence (rather than
manipulation of differential density of the phases, for example, by adding
water
having a high salt concentration).
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In various embodiments, the geometry, velocity, overall volume of the aqueous
component added or a combination thereof may be varied to optimize emulsion
conditioning (e.g., destabilization and coalescence) to enhance downstream
separation. In various embodiments, the contacting may be effected using
various
directional flows of aqueous component into the hydrocarbon-comprising
emulsion. In various embodiments, the aqueous component is contacted with the
hydrocarbon-comprising emulsion as a continuous stream. In various
embodiments, this could also be carried out as a non-continuous aqueous
component addition if the process is dynamically monitored in real time, and
the
aqueous agent is added only when the monitored water cut drops below a certain
set point value. In various embodiments, the contacting may be effected using
a
co-current flow, a counter-current flow, a co-current central flow, counter-
current
central flow or a combination thereof as is illustrated in Figures 9 to 11. In
various
embodiments, the aqueous component may be dispensed using a low shear
contacting device (e.g., a low shear injector). The aqueous component may be
injected in pipe where dispersion of the aqueous component within the
hydrocarbon-comprising emulsion can take place depending on the flow
conditions, properties of the hydrocarbon-comprising emulsion or a combination
thereof. For example, the aqueous component may be dispensed into the
hydrocarbon-comprising emulsion as a spray or as a stream. In other
embodiments, the hydrocarbon-comprising emulsion and the aqueous component
may be mixed using a low shear mixing device configured to promote mixing and
coalescence with as low shear as possible. For example, dispensing of the
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aqueous component, mixing or a combination thereof may be performed using low
shear static mixers, injectors, nozzles or tank mixers with impellers,
turbines,
propellers or paddles, baffles, an inline device or other mechanical device
with or
without energy input without introducing adverse shear. The contacting of the
aqueous component with the hydrocarbon-comprising emulsion according to the
various embodiments, provides an additional control parameter to continuously
optimize performance, for example, the volume of the aqueous component being
added (e.g., water volume being injected). In various embodiments, in which
the
hydrocarbon-comprising emulsion is derived, for example, from an in situ
thermal
process such as SAGD, the emulsion is tight as compared to emulsions derived
from other operations (e.g., crude oil) and therefore more challenging to
process.
Traditionally, processing of such an emulsion has been performed using high
chemical dosages. The present process and system present an advantage over
the prior art processing as they allow a reduction in the use of chemical
processing
aids. For example, in various embodiments, recirculation of the aqueous
component (e.g., water) from the separator to treat the hydrocarbon-comprising
emulsion may increase the effectiveness of injection of other chemical
processing
aids. by allowing use of unspent chemical and increasing dispersion of
chemical,
thus allowing lower overall chemical cost dosages. In further embodiments, the
process and system of the present invention may improve the effectiveness of
removing solids from the emulsion (e.g., washing solids clear of the fluids).
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As was described in the example embodiments above, the aqueous component-
treated emulsion is separated into the hydrocarbon and water constituents in a
separator. The process of separation is also referred to as "emulsion
breaking" or
demulsification over a demusisification time period. The demulsification time
period of the aqueous component-treated emulsion is lesser than a
demulsification time period for the hydrocarbon-comprising emulsion. Based on
Stokes Law, if the viscosity is reduced, the speed of separation will increase
proportionally to this reduction. Furthermore, if the diameter of the droplet
increases, the speed of separation will increase in proportion to the square
of the
factor in which the diameter is increased. In this context, demulsification of
the
hydrocarbon feed is necessarily a matter of degree, reflecting the extent to
which
demulsification proceeds to complete resolution of hydrocarbon and aqueous
phases. As used herein, the term "demulsification" is used to mean that a
generally distinct aqueous phase is resolved from the hydrocarbon phase.
Although a proportion of the aqueous phase may remain emulsified, the emulsion
has been broken to the extent that it gives rise to a distinct aqueous phase
and a
distinct hydrocarbon phase. In various embodiments, the demulsification time
period of the hydrocarbon-comprising emulsion is variable depending on
emulsion properties and equipment configuration. The demulsification time
period can range from minutes to hours or even days if the emulsion is very
tight.
In some embodiments, the demulsification time period of the aqueous
component-treated emulsion (i.e., a modified demulsification time) may be
shorter than the demulsification period of the hydrocarbon-comprising emulsion
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by a factors ranging up to several orders of magnitude if viscosity and
droplet
diameter are successfully manipulated by the aqueous agent and the effect of
coalescence.
For example, Figure 12 illustrates the operation of the FWKO unit and how it
can
be affected by induced coalescence resulting from the treatment of the
hydrocarbon-comprising emulsion with the aqueous component. The purpose of
induced coalescence resulting from the treatment of the hydrocarbon-comprising
emulsion with the aqueous component according to the various embodiments of
the invention is to use velocity, directional change, or imparted energy to
increase speed and effectiveness of coalescing, destabilize droplet surface to
be
coalesced (disruption of surfactants or fine solids), increase water contact
surface area from higher water volumes (when free water volume is greater,
more large droplets coalesce), make use of residual chemical in the water
stream
(i.e., the aqueous component) or a combination thereof. Another indication of
a
more efficient demulsification of the aqueous component-treated emulsion may
be the thickness of the rag layer as compared to the thickness of the rag
layer
obtained from the hydrocarbon-comprising emulsion. In various embodiments,
the quality of the outlet streams from the separation vessels will also
indicate
more efficient demulsification. For example, with efficient demulsification,
there
will be less oil in the produced water outlet stream, less water in the
emulsion or
oil outlet streams, and enhanced (increased) gas liberation from the
separation
vessels. The addition of the aqueous component to the hydrocarbon-comprising
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emulsions according to the various embodiments to recover the hydrocarbon
presents several advantages including hydrocarbon rate of separation
acceleration, enhanced (increased) recovery, enhanced economics or a
combination thereof. Examples of separators suitable for the use in various
embodiments of the present invention include conventional separators such as
for
example a gravity separator (e.g., a vessel or tank), an inclined plate
separator.
In embodiments in which some unresolved residual emulsion remains, this
emulsion may be further treated in a treater. In various embodiments, the
treater
may be a simple gravity separation type, include electrostatic grids for
enhanced
(increased) oil/water separation performance or a combination thereof.
In various embodiments, the process and system of the present invention may be
implemented into an existing processing circuit (for example as a debottleneck
option) or as a new design. In embodiments where the process and system of
the present invention are implemented into an existing processing circuit, the
particulars of implementation will be dependent on the existing system
configuration and operation. For example, in various embodiments, the
hydraulic
limit of the system may need to be calculated or estimated to determine if the
required quantity of the aqueous component (e.g., water recycle or water
addition
from external sources) is within the system limitations. Since there are many
possible factors which could limit the addition of the aqueous component (e.g.
water recycle rate) such as, for example, line hydraulics, pump capacity, pump
CA 02747886 2011-07-29
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head, control valve sizing, vessel residence time, equipment dimensions, or a
combination thereof, the specific implementation should include a careful
evaluation of the system. In particular embodiments, examples of specific
limitations that may be encountered include reduced residence time in the
inlet
degasser due to increased total fluid throughput. In such embodiments, the
aqueous component addition (e.g., water recycle) may be increased to a point
where gas liberation is maximized for the specific system design
configuration.
Increasing the aqueous component rate (e.g., water recycle rate) beyond this
point may reduce the residence time or conflict with other vessel design
features
and potentially cause degradation in the gas removal performance beyond this
"optimum" point. In some embodiments, there may be exchanger limitations such
as facility heat integration considerations, pressure drop increase (due to
increased hydraulic throughput), vibration or erosion limits or a combination
thereof that should be considered.
In various embodiments, the operation of the separator (e.g., the Free Water
Knock Out (FWKO)) may also need to be evaluated to determine any operational
limits reached due to increased water and total fluid throughput. For example,
in
the FWKO with water recycle as the aqueous component (e.g., using water
recycle upstream of inlet degasser or upstream of FWKO or upstream of both the
inlet degasser and the FWKO), hydrocarbon and water separation will be
enhanced (increased) up to a maximum point, where additional water recycle
may not provide immediate benefit as vessel residence time and the physics
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defining the speed of phase (gas, hydrocarbon, water) separation becomes
limiting. In such an embodiment, the system and process may be designed such
the equipment operational limits may be compensated for by other downstream
equipment. Such modifications should be evaluated on a case by case basis.
In various embodiments, other considerations the that may be taken into
account
include, for example, physical limitations within the facility, available pipe
rack
space, tie-in location, existing control scheme or logic or some other factors
which would not allow contacting of the aqueous component (e.g., water
injection) at one or more of the preferred locations (e.g., upstream of the
inlet
degasser, upstream of the exchanger(s), upstream of the FWKO). In
embodiments, in which the preferred or optimum aqueous component contacting
(e.g., water injection) location is not available, the aqueous component could
be
added at an alternate location deemed to be the best available compromise for
the particular processing circuit. In various embodiments, if more practical,
an
existing injection or recycle line (if some other product is injected or
recycled) into
an acceptable location may be chosen. One consideration may involve a
determination of whether the recycle water (aqueous component) is compatible
with the pre-existing injection or recycle material.
In various other embodiments, the process and system of the present invention
may be a new design facility. In various embodiments, in this implementation,
the
preferred location of the contacting of the aqueous component with the
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hydrocarbon-comprising emulsion (e.g. water addition) may be upstream of the
inlet degasser, alone or in combination with provisions for the addition of
the
aqueous component into a location upstream of the separator (e.g. FWKO). A
factor to be considered in the various embodiments of this implementation
includes, for example, the intended maximum quantity of the aqueous
component (e.g. recycled water) for the initial design of the vessels and
piping
systems so as to account for the increase volume of liquid which must be
handled, which includes consideration of system hydraulics and instrumentation
control philosophy and logic. The preferred location of the contacting of the
aqueous component (e.g, water injection) with the hydrocarbon-comprising
emulsion and chemical injection may be upstream of the inlet degasser and
upstream of the FWKO, although other contacting locations could be selected
based on actual plant configuration to achieve the same result and effect on
the
emulsion. Diluent injection, if required for the process, may be effected
upstream
of the exchanger or upstream of FWKO. The preferred location for diluent
addition may be upstream of the heat exchanger in order to aid in viscosity
reduction and prevent fouling in the exchanger. In various embodiments, the
exact location would be dependent on process conditions and fluid properties.
Implementation of the process and system of the present invention to a new
facility can facilitate increased emulsion treating capacity throughput for a
given
equipment size by reducing the necessary residence time for separation to
occur,
reduced equipment size for a given throughput as compared to a design which
does not include this method or a combination thereof.
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In various embodiments, for example, in which the new process is designed or
an existing process has already been designed to use a range of diluents which
may be selected for use from time to time, based on availability or other
economic factors. The diluents to be used could range from a synthetic crude
to
a much lighter hydrocarbon such as condensate, for example. In the case of
synthetic crude being used as a diluent in the process, the addition of an
aqueous agent to reduce the overall emulsion viscosity (due to the heavier
synthetic crude diluent being used) would be beneficial.
In various embodiments, for example, in which the process and system of the
present invention are implemented into either an existing facility or a new
facility,
and in which recycled aqueous component is used (e.g., water recycle), the
recycling may be modulated in a number of ways. In selected embodiments,
modulation of the contacting of the aqueous component with the hydrocarbon-
comprising emulsion (e.g. water injection control) may include a fixed water
rate,
a variable water rate or a combination of these control methods. For the fixed
water recycle rate, the preferred method may involve a determination of the
minimum desired water recycle rate to achieve the altered emulsion viscosity
curve, while considering the possible equipment limitations (e.g., hydraulic
throughput limits), and recycle this fixed quantity of water regardless of the
inlet
emulsion rate or emulsion condition. A design margin may be added to the water
recycle flow rate to ensure the emulsion is always operating in the water
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continuous phase. In various other embodiments, the flow rate of the aqueous
component (e.g., water flow rate) may also be varied based on a fixed ratio of
total emulsion inlet flow to required water recycle rate, or the water recycle
rate
could be varied on a combination of inlet emulsion water cut (e.g., determined
via
manual sample, automatic measurement, or material balance methods) to total
emulsion inlet rate. In various embodiments, this method of dynamic control
may
be desirable in the case of a facility in which the process and system of the
present invention are retrofit to remain within the equipment limitations. In
various embodiments, feed forward or feedback control may be implemented
based on historical or predicted inlet conditions and anticipated dynamic
response of the control system.
Examples of advantages provided by the process and method of the present
invention relate to:
(1) economic benefits arising from recycling any residual chemical in the
produced water (aqueous component), e.g., reduction in consumption of
chemical processing aids typically employed in breaking hydrocarbon
emulsions;
(2) lowered viscosity and increased coalescence within the aqueous
component-treated emulsion;
(3) enhanced gas liberation from the aqueous component-treated emulsion;
(4) reduced equipment fouling (e.g., heat exchanger fouling);
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(5) enhanced chemical processing aid distribution within the aqueous
component-treated emulsion (e.g., diluent distribution);
(6) enhanced separation in downstream processing (e.g., reduction in
bottleneck, increase in processing capacity);
(7) adding stability to a continuous process by ensuring consistent fluid
properties (i.e., viscosity) of the emulsion into the facility, reducing the
probability of pressure fluctuations causing process upsets or a
combination thereof;
(8) improved heat transfer due to decreased bulk emulsion viscosity,
reduced occurrences of viscous fouling on heat exchangers;
(9) the process and system of the present invention may be used alone or in
conjunction with other emulsion breaking strategies such as but not
limited to, diluent addition or demulsification chemical injection;
(10)enhanced separation, particularly of complex tight emulsions (e.g,
emulsions comprising water, heavy oil (e.g., bitumen), organic solids,
clays (e.g., reduced rag layer formation);
(11)optimization tailored to the particular hydrocarbon-comprising emulsion
characteristics (e.g., multiple aqueous component addition stages or
multiple aqueous component addition and static mixing stages).
(12)enhanced performance of separation, particularly when heavier diluent
(synthetic crude for example) is being used in the process.
The examples below describe further embodiments of the invention.
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EXAMPLES
The examples relate to treating an emulsion derived from SAGD. According to
one embodiment, by way of example only, the hydrocarbon may be a
hydrocarbon derived from a reservoir of bituminous sands. Referring to Figure
13, there is shown a schematic example of an in situ thermal recovery process
such as Steam Assisted Gravity Drainage (SAGD) from which the hydrocarbon-
comprising emulsion may be derived. A typical SAGD process involves softening
of the bitumen in a region in the reservoir to generate the hydrocarbon-
comprising emulsion. The softening of the bitumen involves injecting steam
through an injection well into the region to create a steam chamber. In
various
embodiments, softening the bitumen may further involve injecting a solvent
(not
shown) alone or in combination with other chemical agents such as surfactants
(not shown) into the region to reduce the viscosity of the bitumen. The
hydrocarbon-comprising emulsion is drained from the region into a production
well below the region for recovery of the hydrocarbon. Water (steam) injected
during the SAGD process and interstitial water facilitate the formation of the
hydrocarbon-comprising emulsion. Because of the heterogeneous nature of the
reservoir and the properties of the hydrocarbon recovered during the process
(e.g., bitumen), in various embodiments, the hydrocarbon-comprising emulsion
is
chemically complex, heterogeneous, and comprises a number of other species
(e.g., gas, surfactants, organic and inorganic species, fines), which can
stabilize
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the hydrocarbon-comprising emulsion making it difficult to break in downstream
processing.
An example of a processing circuit which may be used in selected embodiments
for treating the hydrocarbon-comprising emulsion is shown Figure 14. This
embodiment relates to treating the hydrocarbon-comprising emulsion derived
from SAGD.
As is shown in Figure 14, in one process configuration, the hydrocarbon-
comprising emulsion enters the processing circuit first through an inlet
degasser,
and then passes through a heat exchanger (e.g., an emulsion/boiler feed water
heat exchanger). Upstream of the degasser, the hydrocarbon-comprising
emulsion is contacted with the aqueous component to form the aqueous
component-treated emulsion having increased water cut as compared to the
water cut of the hydrocarbon-comprising emulsion. The contacting of the
aqueous component with the hydrocarbon-comprising emulsion is performed in
this embodiment in a region generally adjacent the degasser so as to reduce
the
potential for the formation of a stratified flow. In the degasser, the
entrained
gases are removed and the emulsion is then directed to the heat exchanger for
cooling. It has been observed that the hydrocarbon-comprising emulsion
entering
the inlet degasser is a heterogeneous complex emulsion (e.g., water-oil-water
emulsion) which varies in water cut during its production from the SAGD
operations. One of the problems that was identified with processing the
hydrocarbon-comprising emulsion without treatment with the aqueous
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component related to the exchanger experiencing a higher than normal pressure
drop (e.g., about 300 kPa vs. about 100 kPa), which is undesirable because it
consumes available hydraulic capacity and contributes to plant operating
difficulties. It was observed that the high pressure drop across the
exchangers
appears to occur due to the inlet hydrocarbon-comprising emulsion periodically
crossing this inversion point. It was observed that as a result of increase in
viscosity of the hydrocarbon-comprising emulsion, fouling of the heat
exchanger
occurred which resulted in reduced flow area and thus increased pressure drop
and reduced heat transfer due to fouling.
Sampling of the emulsion water cut and a comparison of the water cut data
against the pressure drop across the heat exchangers indicated that high
pressure drop events occurred in the heat exchangers when the water cut was
low (for example, an average of about 0.56 (i.e., 56%) as compared to an
average of about 0.64 (i.e., 64%) for low pressure drop). Figure 15
illustrates for
example random increases in pressure drop across the heat exchanger(s).
Figure 16 illustrates a typical elevated pressure drop event. It was observed
that
the duration and magnitude of elevated pressure drop events varied but tended
to be associated with downstream treating issues such as for example loss of
clean water phase level in FWKOs, offspec water, wet emulsion being sent to
treaters. The hydrocarbon-comprising emulsion produced from SAGD varies in
properties, and as the relative quantity of the two main emulsion constituents
(i.e.
oil and water) varies, the hydrocarbon-comprising emulsion can undergo an
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inversion in which the liquid continuous phase switches from one constituent
to
the other; i.e., a switch from oil being the continuous phase to water being
the
continuous phase, or visa versa (Figure 2). Generally at this inversion point,
there is a significant increase in the viscosity of the emulsion. Several
factors
were found to influence the emulsion viscosity and stability including: volume
fraction of oil and water phases, viscosity ratio of oil and water phases,
temperature, interfacial tension, vapor loading, shear history (e.g., average
droplet size, droplet size distribution), pH, solids content and size, or a
combination thereof. The treatment of the hydrocarbon-comprising emulsion with
the aqueous component upstream of the degasser, the heat exchanger or both
was found to reduce or eliminate the problem of high pressure drops in the
heat
exchangers. Treatment of the hydrocarbon-comprising emulsion with the
aqueous component according to the various embodiments upstream of the heat
exchangers (i.e., manipulation of the location at which the high viscosity
event
takes place) resulted in a reduction of the fouling of the heat exchanger due
to a
decreased viscosity of the aqueous component-treated emulsion.
As is shown in Figure 14, following cooling in the heat exchanger, the cooled
aqueous component-treated emulsion is then directed to a separator (e.g., free
water knockout units, FWKOs A-D). When the aqueous component-treated
emulsion exits the heat exchanger it remains an emulsion without substantial
phase separation. Separation takes place in the FWKO units. If a portion of
the
aqueous component-treated emulsion does not separate, further separation is
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achieved in the treater units (e.g., treaters A-H). In the absence of the
treatment
of the hydrocarbon-comprising emulsion with the aqueous component at the
selected location to cause the high viscosity event to occur at another
selected
location, it was also observed that treating in general was negatively
impacted,
and in particular resulted in increased gas retention to downstream treating
vessels (e.g., foamy emulsion created), reduced velocity of separation in FWKO
and treaters, control instability or a combination thereof.
The experimental study involved various aspects including:
(1) forcing the emulsion towards the emulsion inversion point (i.e., the high
viscosity event) in a water deficient regime by manipulating field
production (e.g., SAGD field production);
(2) artificially increasing the inlet water cut of the emulsion by, for
example,
recycling produced water from free water knockout units (FWKO) to the
inlet degasser thereby forcing the inlet emulsion feed beyond the
inversion point (i.e., the high viscosity event) and into the water
continuous regime;
(3) artificially increasing the inlet water in (2), by supplementing with a
small
quantity of boiler feed water;
(4) artificially increasing the water cut of the fluid feeding the FWKO by
recycling water from it's own water dump;
(5) monitoring process conditions and collecting data to further investigate
the pressure drop problems in the heat exchangers and associated
treating problems.
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The emulsion samples were obtained from the outlet of the inlet degasser to
establish the starting point for the tests and to determine which high water
producing
wells in the field needed to be manipulated and to establish a base line
starting point
for the test before water addition.
Samples were gathered from the outlet streams of FWKO units (e.g., two trains
to
minimize the quantity of samples that must be handled to give a representative
snapshot of the entire oil treating train).
Once the starting point water cut of the inlet emulsion is established, the
wells which
are high water producers will have flow rates reduced until the desired target
inlet
water cut is achieved or the maximum allowable production cuts have been
reached.
The manipulation of the production wells is only one aspect which may be used
to
modulate the water cut in particular embodiments. The water cut of the
emulsion
may be modulated without manipulation of the output of the production wells.
In another experiment, water cut of the hydrocarbon-comprising emulsion
derived
from in situ thermal processes such as for example SAGD was modulated using
addition of water, and in particular addition of water from for example one or
both
of the following sources:
(1) produced water (PW) recycled from FWKO via a desand jet pump directly
into the inlet degasser. The water pressure and flow were controlled.
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(2) boiler feed water addition (BFW) (e.g., into the inlet produced emulsion
pipe).
In some embodiments, the more desirable option may be to add water using the
produced water as the temperature is closer to that of the inlet produced
emulsion. However, if a large enough volume of produced water to increase the
water cut above the inversion point or to cause an observable change in the
performance of the downstream exchangers or treating trains cannot be
obtained, supplemental boiler feed water can be added.
Water (aqueous component) may be added at various addition points. For
example, water could added using a recycle line from the pump back to the
inlet
emulsion of the FWKO as is shown in Figure 17. This would artificially
increase
the water cut in the emulsion to the FWKO "B" train from about 0.56 to about
0.63, considering that the maximum pump capacity in this experiment of about
28
m3/h was recycled. The initial results obtained may be assessed as to the
impact
of injected water into the degasser to determine whether to continue with the
produced water injections through the desand system or divert water to the
inlet
of a FWKO via the minimum flow recycle line.
As this would only affect the one train, samples can be taken from the FWKO
and treaters in order to assess if the increase in water cut resulted in
decreased
treating difficulties. The water dumps of the treaters and FWKOs can be
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monitored to assess water quality, and the emulsion outlets of the FWKOs will
be
monitored for downstream operations.
If water is injected prior to the emulsion entering FWKO, the effect of an
increase
in water cut on the heat exchangers will not be observed, as the injection
point is
downstream of the exchangers. However, this will allow a comparison between
the FWKO train with the addition of an aqueous component and the other trains
to observe if increasing the water cut resolved treating issues in the FWKO
and
treater vessels for the particular emulsion studied.
Baseline data collection relating to a water cut for a particular emulsion to
be
treated may be obtained by taking samples over a period of time at a selected
frequency prior to treatment. The samples may be taken for example from the
outlet of the degasser, the water dumps of the FWKOs and treaters, and the
emulsion outlets of the FWKOs. An alternative to taking samples from the water
dumps of FWKOs and treaters is to take samples at the inlet of the skim tanks
to
determine overall change in water quality, rather than from each individual
train.
The emulsion samples were analyzed for water cut, and the water cut of the
emulsion from the degasser was used as data for trending produced emulsion
water cut against high pressure drop instances. The FWKO outlet emulsion water
cut provided an indication whether the addition of produced water aided in
hydrocarbon/water separation in the FWKOs, reducing the amount of water in the
emulsion fed into the treaters or a combination thereof. The water dumps were
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sampled to assess whether the addition of produced water increased the water
quality. These samples were measured against historical data to measure water
quality improvement. Measurement of the taps of FWKOB, treater C and treater
D for example can be used to determine the number of taps of water, as well as
the water cut in the lowest oil tap, which can provide an indication of a
tightening
of the rag layer. For example, as the rag layer tightens, less water will be
mixed
into the oil at the interface, and therefore the water level in the vessel
should be
higher.
Prior to the start of monitoring of the emulsion, production may be shifted
more
heavily to high oil producing wells and limited in high water producing wells
in
order to obtain produced emulsion with a low water cut coming into the plant.
The
effects of water addition to the emulsion will be more obvious if the trial is
carried
out while production problems are occurring.
Examples of the advantages offered by monitoring and treating the emulsion
related to for example increased production, reduced operating costs, safety,
environmental advantages or a combination thereof. The high pressure drops
observed across the heat exchangers result in a process bottleneck and
therefore increased inlet degasser operating pressure and decreased operating
pressures of the FWKOs and treaters. Treating the hydrocarbon-comprising
emulsion with the aqueous component according to the various embodiments
described facilitates a reduction in the occurrence of heat exchanger high
pressure excursions therefore reducing treating difficulties associated with
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increased pressure drops across the heat exchangers, increasing process
stability thereby allowing future production increases, increasing quality of
all
streams leaving the oil treating trains or a combination thereof.
Figures 18 and 19 illustrate a correlation between low water cut and increased
instances of high pressure drop. Figure 18 shows a data histogram for the
instances of low pressure drop observed across the heat exchangers. The x-axis
is water cut and the y-axis is the number of observed samples at given water
cut.
It can be seen that the mean for this data set is about 0.64. Figure 19 shows
a
data histogram for instances of high pressure drop observed across the heat
exchangers. The mean for this data set is about 0.56.
Figure 20 and Figure 21 illustrate calculated basic sediment and water (BSW)
to
FWKOs and heat exchanger pressure drop.
Figure 2 illustrates a graph of viscosity vs. oil cut curve depicting a spike
in
viscosity at the emulsion inversion point or region.
An experiment was conducted without manipulating the field production. The
experimental set up is shown in Figure 22. In this experiment, a limited
amount of
flow was available for recycle to the inlet degasser (e.g., maximum about 55
m3/h
with produced water recycle and boiler feed water recycle), corresponding to
an
increase in water cut of only approximately 1%. Additionally, there was poor
mixing as the produced water, which constituted about 47 m3/h of recycled
water,
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was being injected through the downwards pointing desand jets of the inlet
degasser. This promoted formation of a water layer at the bottom of the vessel
and did not allow for the water to be mixed with the emulsion in order to
increase
overall water cut. Other factors that had a negative impact in this experiment
were, for example, poor sampling points.
It was decided that due to the complications with obtaining representative
results
while recycling water to the degasser, the water recycle would be redirected
to
the inlet of the FWKO. The produced water was injected upstream of the static
mixer, so sufficient mixing was obtained. The actual recycle flow rates that
were
obtained in this part of the experiment are outlined in the flow diagram in
Figure
17.
In this experiment, the aim of recycling water to the FWKO was to demonstrate
the effects of water recycle on separation and treating. Based on Stokes' Law,
decreasing the viscosity of the emulsion will increase separation velocity and
allow for a greater degree of separation by the outlet end of the vessel.
Increasing the water cut of the emulsion will ensure that the viscosity
remains
closer to that of pure water and will reduce the likelihood for emulsion
inversion
and the corresponding increase of viscosity.
V D 2 \Pa - PJg
18~e
(Formula 1)
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where: v = velocity of droplet, D = droplet diameter, pd and Pe = density of
droplet
and emulsion, respectively, g = gravity,
Figure 23 illustrates schematic diagrams showing good resolution and poor
resolution respectively. Figure 24 shows unresolved emulsion layer indicative
of
poor separation, and Figure 25 shows smaller unresolved emulsion layer
indicative of good separation.
During elevated pressure drop events under regular process conditions, the
separation obtained in the vessel declines and as a result there is a greater
oil &
grease (O&G) content in the produced water dump, leading to off spec water,
and a greater carryover of water from the FWKOs to the treaters, which can
result in off spec oil. With the water recycle turned on, it was observed that
better
resolution was obtained in the vessel, supporting that produced water recycle
enhances separation. Additionally, during elevated pressure drop events, while
the unresolved emulsion layer still expanded to an extent, it was more
resolved
than during an elevated pressure drop event with no produced water recycle.
The
results are illustrated in Figure 26 and Figure 27 showing data in connection
with
produced water recycle to the FWKO, and further in Figure 28 showing the
effect
of water cut on pressure drop and separation.
The circled section in Figure 26 shows how unresolved the emulsion was during
high pressure drop occurrences with no water recycle on, as Tap 6 and Tap 7
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had approximately the same water cut, indicating that the unresolved layer was
expanded. This figure also illustrates that as the water recycle was turned
on,
there was an immediate effect on the resolution within the vessel. Tap 6 went
to
about 100% water, and the water content of Tap 7 decreased to below about
50%. Compared to the second elevated pressure drop event depicted in Figure
26, where there is an elevated pressure drop across the heat exchangers with
produced water recycle on, there is much better resolution, even though there
is
still an observed drop in water cut of Tap 6 indicating that more oil is
present at
this point and that separation has decreased slightly. When the elevated
pressure drop breaks, good resolution is again observed.
Figure 27 illustrates that good resolution is being maintained with the water
recycle on. There is a decrease in resolution as another elevated pressure
drop
event is occurring. At the point in which the produced water recycle is
stopped,
resolution immediately deteriorates and the unresolved layer expands,
resulting
in loss of resolution. After the water recycle was stopped, the clean water
level
moved from Tap 6 to Tap 4.
Figure 28 illustrates the % of water in the FWKO inlet and outlet emulsion, as
well as the heat exchanger pressure drop trend. From this data, the elevated
pressure drop event is followed immediately by a drop in BS&W to the FWKO. As
the BS&W meter is downstream of the heat exchangers, this correlates to an
elevated pressure drop event at the time that the reduced water content
emulsion
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was travelling through the heat exchangers. Additionally, the water cut of the
emulsion out of the FWKO increased during the elevated pressure drop,
indicating that separation is negatively impacted when there is a high
pressure
drop and as a result more water is present in the outlet emulsion.
The experiments conducted indicate that during low pressure drops across the
heat exchangers, there is a clearly resolved emulsion layer, during high
pressure
drops across the heat exchangers, the emulsion layer becomes less resolved
and expand, during high pressure drops across the heat exchangers with
produced water addition, the emulsion layer becomes more resolved and the
expanse over which it extends is reduced, and during high pressure drops
across
the heat exchangers with produced water addition stopped, the emulsion layer
immediately thickens and the resolution decreases.
The benefits of water recycle to the FWKO were evident from the experiments
with respect to enhanced (increased) separation of water and emulsion in the
vessel. Additional benefits include:
(1) a reliable interface control - if unresolved emulsion layer thickness is
reduced, an improved detection of the difference in fluid properties used
by the specific level technology (e.g. density, dielectric constant, etc.) may
be obtained and provide a more stable interface level output than when
the unresolved emulsion layer is expansive. For example, when the two
components are thoroughly mixed with a gradual transition to oil, the
detection of differences in the fluid properties is difficult.
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(2) increased treating capacity - better separation (e.g., Figure 29) allows
the
ability to increase production rates and ensure that oil and water do not go
off spec.
(3) improved gas removal in the FWKOs, treaters or both (e.g., Figure 30) -
gas is seen to carry through the inlet degasser to the downstream treating
vessels during high pressure drop events. If the viscosity of the emulsion
in these vessels is reduced, the gas will be better able to break out.
(4) cleaner water dumps - less oil lower in the vessel will ensure cleaner
produced water
(5) dryer oil to treaters - better separation means more water has moved to
the bottom of the vessel and will be dumped as water rather than being
carried through the emulsion to the treaters. The treaters were designed
for about 10% to about 20% water in the inlet emulsion, but are currently
receiving emulsion with a water cut between about 20% to about 40%.
(6) lower chemical consumption - currently, chemical rates are increased
during high pressure drop events when there is poor separation, in order
to aid in resolving the emulsion. If this can be done with water, as shown
in the trial, chemical rates can be reduced, resulting in large cost savings.
(7) limited need for tap checkers - if auto interface control is implemented,
there will be a reduced need for tap checkers.
Although specific embodiments of the invention have been described and
illustrated, such embodiments should not be construed in a limiting sense.
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Various modifications of form, arrangement of components, steps, details and
order of operations of the embodiments illustrated, as well as other
embodiments
of the invention, will be apparent to persons skilled in the art upon
reference to
this description. It is therefore contemplated that the appended claims will
cover
such modifications and embodiments as fall within the true scope of the
invention. In the specification including the claims, numeric ranges are
inclusive
of the numbers defining the range. Citation of references herein shall not be
construed as an admission that such references are prior art to the present
invention.
