Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
A8141898CA
SYSTEM AND METHOD FOR SHORTENED-PATH PROCESSING OF
PRODUCED FLUIDS AND STEAM GENERATION
TECHNICAL FIELD
[0001] The present disclosure generally relates to systems and
methods for
, processing fluids produced during in-situ hydrocarbon recovery and for
generating
steam therefrom. In particular, the present disclosure relates to efficient
systems and
abbreviated processes for treating produced emulsions to facilitate steam
generation
proximate to a well pad.
BACKGROUND
[0002] Viscous hydrocarbons can be extracted from some subterranean
reservoirs using in-situ recovery processes. Some in-situ recovery processes
are
thermal processes wherein heat energy is introduced to a reservoir to lower
the
viscosity of hydrocarbons in situ such that they can be recovered from a
production
well. In some thermal processes, heat energy is introduced by injecting a
heated fluid
¨ typically steam, solvent, or a combination thereof¨ into the reservoir by
way of an
injection well that is situated at a well pad. Steam-assisted gravity drainage
(SAGD)
and cyclic steam stimulation (CSS) are representative thermal-recovery
processes
that use steam to mobilize hydrocarbons in situ. Solvent-aided processes (SAP)
and
solvent-driven processes (SDP) are representative thermal-recovery processes
that
use both steam and solvent to mobilize hydrocarbons in situ.
[0003] Regardless of whether a recovery process uses steam alone
(e.g.
SAGD/CSS) or in combination with solvent (e.g. SAP/SDP), in situ recovery
yields a
produced-fluid stream that is likely to contain a mixture of produced water,
produced
oil, and one or more dissolved or entrained materials derived from the
reservoir
undergoing the hydrocarbon-recovery process. There are advantages associated
with using the produced water as a feedstock for steam generation ¨ namely
that the
produced water can be recycled during the recovery process thereby increasing
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system efficiencies and reducing environmental impacts. However, these
advantages
may be at least partially offset by challenges associated with the recycling
process in
its conventional form.
[0004] In a conventional produced-water recycling process, the
produced-fluid
stream is transported from the well pad to a central processing facility where
oil-water-
separation, water-treatment, and steam-generation processes are completed to
provide steam. The steam is then transported back to the well pad for re-
injection into
the reservoir. Transporting the produced fluids from the well pad to the
central
processing facility requires infrastructure, which increases system
complexity.
Likewise, transporting steam from the central processing facility to the well
pad
requires infrastructure, which increases system complexity. This complexity is
compounded by the need to mitigate against heat-loss during steam
transportation.
Accordingly, there is a need for systems/methods that allow for produced-fluid
processing and steam generation at or near the well pad. However, central
processing facilities remain the de-facto choice among producer companies and
industry professionals as well-pad-scale installations based on current
technologies
are not economically viable.
SUMMARY
[0005] It is generally accepted that large-scale steam generation for
hydrocarbon recovery operations necessitates the use of feed water that has
been
heavily treated to ensure specific water-chemistry parameters are maintained.
In
particular, it is widely held that the silica content and the hardness content
of a feed-
water stream must be lower than about 50 ppm and about 0.5 ppm, respectively,
in
order to mitigate against unwanted occurrences such as scale accumulation.
However, in view of recent advances in steam-generation technology, the
proposition
that such restrictive water-chemistry parameters are necessary for large-scale
steam
generation should be reconsidered. The systems and methods of the present
disclosure utilize steam-generation technologies that are capable of large-
scale
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steam generation from feeds that include higher-than-conventionally-acceptable
impurity levels. In particular, the systems and methods of the present
disclosure
utilize such steam-generation technologies in combination with emulsion-
treating
technologies and de-oiling technologies that are suitable for high-temperature
and
high-pressure applications. As such, the systems and methods of the present
disclosure are based on unique combinations of process components that, taken
together and operated in accordance with the teachings of the present
disclosure,
allow for high-temperature and high-pressure processing of produced fluids and
steam generation. By obviating the requirement for fluid-treatment processes
that
operate under low-temperature/low-pressure conditions, the systems and methods
of
the present disclosure substantially reduce the complexity and equipment-
footprint
associated with fluid processing and steam generation. In view of this reduced
complexity and footprint, the present disclosure provides systems and methods
that
are suitable for use at or near a well pad. This provides for further process
efficiencies
by obviating the need for produced-fluid and/or steam-piping infrastructure
to/from a
central processing facility. Briefly stated, the present disclosure provides
for
shortened-path fluid processing and steam generation.
[0006] In select embodiments, the present disclosure relates to a
system for
processing fluids at a location that is proximate to a well pad. The system is
for use
in the context of a thermal process for recovering hydrocarbons from a
subterranean
reservoir.
[0007] The system comprises an emulsion-treating sub-system that is
operable to separate an oil-water emulsion produced from the subterranean
reservoir
into a produced-oil stream and an oily produced-water stream. The system is
configured to maintain the temperature of the oily produced-water stream above
the
normal boiling point thereof and to maintain the pressure of the oily produced-
water
stream above ambient atmospheric pressure. The emulsion-treating sub-system is
configured to separate the oil-water emulsion such that the oily produced-
water
stream has an average residual-oil concentration of less than about 10,000
ppm, an
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average silica content of at least about 20 ppm, and an average hardness
content of
at least about 5 ppm.
[0008] The system further comprises a de-oiling sub-system that is
operable
to treat the oily produced-water stream to provide a de-oiled-water stream.
The
system is configured to maintain the temperature of the de-oiled-water stream
above
the normal boiling point thereof and to maintain the pressure of the de-oiled-
water
stream above ambient atmospheric pressure. The de-oiling sub-system is
configured
to treat the oily produced-water stream such that the de-oiled-water stream
has an
average residual-oil concentration of less than about 25 ppm, an average
silica
content of at least about 20 ppm, and an average hardness content of at least
about
5 PPrn=
[0009] The system further comprises a steam-generating sub-system.
The
steam-generating sub-system is operable to generate steam having an average
quality of at least about 75 % from an input stream that comprises fluids from
the de-
oiled-water stream. The input stream has an average residual-oil concentration
of
less than about 25 ppm, an average silica content of at least about 20 ppm,
and an
average hardness content of at least about 5 ppm. The system is configured to
maintain the temperature of the input stream above the normal boiling point
thereof
and to maintain the pressure of the input stream above ambient atmospheric
pressure.
[0010] In select embodiments, the present disclosure relates to a
method for
processing produced fluids. Likewise, in select embodiments, the present
disclosure
relates to a method for generating steam from a produced-fluid stream that
comprises impurities. Method-related embodiments of the present disclosure are
suitable for implementation at a location that is proximate to a well pad.
Method-
related embodiments of the present disclosure are for use in the context of a
thermal process for recovering hydrocarbons from a subterranean reservoir.
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[0011] Method-related embodiments of the present disclosure comprise
separating an oil-water emulsion produced from the subterranean reservoir into
a
produced-oil stream and an oily produced-water stream. The temperature of the
oily
produced-water stream is maintained above the normal boiling point thereof and
the
pressure of the oily produced-water stream is maintained above ambient
atmospheric pressure. The oily produced-water stream has an average residual-
oil
concentration of less than about 10,000 ppm, an average silica content of at
least
about 20 ppm, and an average hardness content of at least about 5 ppm.
[0012] Method-related embodiments of the present disclosure further
comprise de-oiling the oily produced-water stream to provide a de-oiled-water
stream. The temperature of the de-oiled-water stream is maintained above the
normal boiling point thereof and the pressure of the de-oiled-water stream is
maintained above ambient atmospheric pressure. The de-oiled-water stream has
an
average residual-oil concentration of less than about 25 ppm, an average
silica
content of at least about 20 ppm, and an average hardness content of at least
about
5 PPm=
[0013] Method-related embodiments of the present disclosure further
comprise
generating steam having an average quality of at least about 75 % from an
input
stream that comprises fluids from the de-oiled-water stream and that has an
average
.. residual-oil concentration of less than about 25 ppm, an average silica
content of at
least about 20 ppm, and an average hardness content of at least about 5 ppm.
The
temperature of the input stream is maintained above the normal boiling point
thereof.
The pressure of the input stream is maintained above ambient atmospheric
pressure
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] These and other features of the present disclosure will become more
apparent in the following description in which reference is made to the
appended
drawings. The appended drawings illustrate one or more embodiments of the
present
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disclosure by way of example only and are not to be construed as limiting the
scope
of the present disclosure.
[0015] FIG. 1 is a schematic illustration of a prior art process for
separating,
treating, and generating steam from a produced-fluid stream.
[0016] FIG. 2 is a schematic illustration of a first shortened-path
produced,fluid
processing and steam-generation process in accordance with the present
disclosure.
[0017] FIG. 3 is a schematic illustration of a second shortened-path
produced-
fluid processing and steam-generation process in accordance with the present
disclosure.
[0018] FIG. 4 is a plot of fluid density as a function of temperature for a
water
sample and a bitumen sample.
DETAILED DESCRIPTION
[0019] Steam-assisted gravity drainage (SAGD) and cyclic steam
stimulation
(CSS) are representative thermal-recovery processes that use steam to mobilize
.. hydrocarbons (e.g. bitumen and/or heavy oil) in situ. Solvent-aided
processes (SAP)
and solvent-driven processes (SDP) are representative thermal-recovery
processes
that use both steam and solvent to mobilize hydrocarbons in situ. Regardless
of
whether a recovery process uses steam alone (e.g. SAGD/CSS) or in combination
with solvent (e.g. SAP/SDP), in-situ recovery yields a produced-fluid stream
that is
likely to contain a mixture of produced water, produced oil, and one or more
dissolved
or entrained materials derived from the reservoir undergoing the hydrocarbon-
recovery process. There are advantages associated with using produced water as
a
feedstock for steam generation. However, these advantages may be offset by
challenges associated with the necessity to treat produced water to obtain
treated
water that is suitable as a feedstock for steam generation. In particular,
recycling
produced water typically requires substantial reductions in residual-oil
content, silica
content, hardness content, total-suspended-solids content, soluble-organics
content,
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and/or turbidity. In thermal hydrocarbon-recovery processes, water treatment
is often
complex and/or expensive, and water treatment can be challenging to manage, as
the composition of a produced-water stream is likely to vary over time.
Furthermore,
conventional water-treatment processes are often sub-optimal in that they are
designed to function at temperatures and pressures that are substantially
lower than
those typical of produced water. It is inefficient to cool and de-pressurize
produced
water for treatment given that high temperatures and high pressures are
required for
steam generation. In addition, the footprint of conventional water-treatment
processes and systems may be substantial.
[0020] FIG. 1 is a schematic illustration of a conventional system 100 for
separating, treating, and generating steam from a produced-fluid stream. In
the
conventional process 100 a produced-fluid steam is received at a well pad and
directed to a central processing facility by way of produced-fluid-transport
infrastructure 101. At the central processing facility, the produced fluid is
subjected to
an emulsion-treatment sub-process 102 to provide coarse oil-water separation.
The
coarse oil-water separation provides an oily produced-water stream that
typically
contains residual oil, silica, hardness, suspended solids, and/or solubilized
organic
compounds, and it is common practice to treat the oily produced-water stream
to
provide a treated-water stream that is suitable for use as a feedstock for
steam
generation. Accordingly, the conventional process 100 includes a heat-exchange
sub-process 104 to reduce the temperature of the oily produced-water stream to
a
temperature that it is suitable for a de-oiling sub-process 106 and a water-
treatment
sub-process 108. Subjecting the produced-water stream to the de-oiling sub-
process
106 and the water-treatment sub-process 108 provides a treated-water stream
that
is then re-heated in a heat-recovery sub-process 110 and input into a steam-
generation sub-process 112 to generate steam. The steam is then directed back
to
the well pad by way of steam-transport infrastructure 114.
[0021] The emulsion treatment sub-process 102 typically involves a
number of
distinct steps and parameters as follows. Oil-water emulsion from the
reservoir may
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vary in temperature and pressure. For example, the produced-fluid stream may
have
a temperature between about 80 C and about 250 C (typically between about
180
C and about 220 C) and a pressure of between about 1,200 kPag and about 2,000
kPag. After emulsion is recovered from the reservoir, it may be degassed and
then
cooled to between about 130 C and about 140 C to allow for diluent-aided
separation. The cooled emulsion may then be treated for coarse oil-water
separation,
for example in a free-water knock out unit, and/or another emulsion treater.
For
traditional gravity separation, this typically occurs at a pressure of between
about 800
kPag and about 1,500 kPag and at a temperature of between about 130 C and
about
140 C. Alternatively, for flash treating (for example), coarse oil-water
separation
typically occurs at a pressure of between about 100 kPag and about 800 kPag
and a
temperature of between about 130 C and about 140 C. These conventional
emulsion-treating systems typically use a diluent to aid in separation of oil
and water.
The diluent is traditionally a pentane rich natural gas liquid or a synthetic
crude oil.
The diluent typically remains in the de-watered oil, which is typically cooled
and sent
to sales oil tanks.
[0022] The heat-exchange sub-process 104 typically involves one or
more
heat exchangers to decrease the temperature of the oily produced-water stream
from
between about 130 C and 140 C to a low temperature such as between about 80
C and about 95 C. At the same time, the oily produced-water stream is
typically de-
pressurized to a low pressure such as atmospheric pressure to accommodate the
inlet specifications for the de-oiling sub-process 106 and/or the water-
treatment sub-
process 108.
[0023] The de-oiling sub-process 106 typically involves passing the
oily
produced-water stream through a series of units including a skim tank for
gravity
separation, a flotation unit (such as an induced gas flotation unit or an
induced static
flotation unit) for further removal of suspended solids, and a filtration unit
(such as' an
oil-removal filter unit) to provide a de-oiled water stream. The de-oiling sub-
process
106 may also include a chemical treatment.
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[0024] The water-treatment sub-process 108 typically involves passing
the de-
oiled-water stream through a lime-softening sub-process and an ion-exchange
sub-
process to provide the treated-water stream. The lime-softening sub-process
increases the pH of the de-oiled water stream by introducing lime thereto.
This serves
to remove hardness in the form of calcium and magnesium as carbonate
precipitates.
The lime-softening sub-process may also be configured to remove silica to
ensure
the treated-water stream meets the specifications of the steam-generation sub-
process 112. The ion-exchange sub-process may be configured to remove
inorganic
cations (such as Li, Ca2+, Mg2+, and Fe3+) for similar reasons. For example,
typical
steam-generation feed streams may be required to contain less than 50 ppm
silica,
less than 1 ppm hardness, and less than 1 ppm oil so that boiler-manufacturer-
recommended parameters (i.e. less than 100 ppm silica oxides and less than 1
ppm
hardness as expressed as CaCO3) are adhered to even when accounting for upset
conditions.
[0025] The decrease in temperature and pressure of the oily produced-water
stream is necessary in conventional systems and processes for several reasons.
For
example, operation of the various units (e.g. the skim tank, the induced gas
flotation
unit and/or the lime softener) at high pressure would be economically
unfavorable
when compared to operation at atmospheric pressure. As well, a number of the
units
require lower temperature for effective operation. A significant decrease in
temperature of the produced-water stream entering de-oiling is generally
understood
to be necessary for operational reasons, particularly so that surge capacity
may be
carried out at atmospheric pressure in tanks.
[0026] In the heat-recovery sub-process 110, the treated-water stream
passes
through a series of heat exchangers to recover at least some of the enthalpy
forfeited
during the heat-exchange sub-process 104. The pressure of the treated-water
stream
is also typically increased through pumping. As such, the treated-water stream
is
typically pre-conditioned before it is used as a feed stream (i.e. boiler-feed
water) for
the steam-generation sub-system 112. It will be evident to those skilled in
the art that
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the heat-exchange sub-process 104 and the heat-recovery sub-process 110
typically
require substantial investments in equipment and energy input as boiler-feed
water
is typically input into a steam generator at a temperature of between about
180 C
and about 200 C.
[0027] The steam-generation sub-system 112 typically involves a number of
distinct steps as follows. The pre-heated boiler-feed water typically enters
an
economizer section, which further heats the boiler-feed water using convection
from
flue gas, and then the boiler-feed water enters the fired section of the
boiler.
Conventional once-through steam generators typically produce steam having a
quality of between about 75 % and about 90 % at pressures between about 7 MPa
and 15 MPa, which is considered as standard in the industry. Optionally,
produced
steam may be separated into dry steam and a liquid fraction that contains
impurities.
The dry steam is typically sent to one or more well pads for use in the
reservoir during
the hydrocarbon-recovery process. The liquid fraction separated from the
generated
steam (referred to as boiler blowdown) is typically sent for recycling or
disposal.
Steam separation is typical for SAGD but not for all thermal in-situ
processes.
[0028] In view of conventional processes such as the one shown in
FIG. 1, in
the context of the present disclosure it has been determined that there is an
unmet
need for systems/methods that allow for a shortened path for produced-fluid
processing and steam generation at or near a well pad (i.e. proximate to a
well pad
and remote from any central processing facility as discussed, for example,
with
respect to FIG. 2 and FIG. 3 below). The systems/methods of the present
disclosure
enable such processing by utilizing a select combination of complementary
technologies for emulsion treating, de-oiling, and steam generation. The steam-
generation technologies are selected based on their capacity to process feeds
that
include higher-than-conventionally-acceptable impurity levels. Selecting such
technologies removes constraints associated with the low-temperature and low-
pressure conditions typical of conventional water-treatment processes. The
emulsion-treating technologies and the de-oiling technologies are selected to
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complement the steam-generation technologies in order to leverage the absence
of
such temperature/pressure constraints. In particular, the emulsion-treating
technologies and the de-oiling technologies are selected based on their
capacity to
process feeds at high temperature and high pressure. As such, the present
disclosure
provides unique combinations of processing technologies that, when integrated
and
operated in accordance with particular processing parameters set out herein,
provide
for efficient systems and abbreviated methods for produced-fluid processing
and
steam generation. In other words, the present disclosure provides for
shortened-path
produced-fluid processing and steam generation (herein referred to as
shortened-
path SAGD (SP-SAGD)). However, those skilled in the art will understand that
hydrocarbon recovery technologies other than SAGD, such as those described
below, are intended to be incorporated herein. Shortened-path processing and
steam
generation serves to: (i) reduce the energy input required for steam
generation by
retaining a substantial amount of the latent heat energy and pressure of the
produced
fluids throughout the process; (ii) reduce or eliminate the requirement for
system
additives (such as diluent for oil-water-emulsion separation); (iii) reduce or
eliminate
the requirement for specific treatment components/steps (such as lime
softeners,
evaporators, and/or ion exchange units); and/or (iv) reduce the amount of
fluid-
transport infrastructure required to execute in-situ hydrocarbon recovery.
[0029] In the following section, the efficient systems and abbreviated
methods
for processing fluids and generating steam proximate to a well pad are
described in
detail. The following description is for illustrative purposes and is not
meant to be
limiting in any way. All reference to dimensions, capacities, embodiments,
substitutions, modifications, optional features and/or examples throughout
this
disclosure (including the drawings) should be considered non-limiting and a
reference
to an illustrative and non-limiting embodiment or an illustrative and non-
limiting
example. Numerous details are set forth to provide an understanding of the
embodiments and examples described herein. The embodiments and examples may
be practiced without these details. In other instances, well-known methods,
procedures, and components are not described in detail to avoid obfuscating
the
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focus of the present disclosure. All ranges referred to herein are intended to
be
interpreted as being a reference to all values of the range and should be
considered
a disclosure of all values within each referred-to range. The description and
claims
are not to be considered as limited to the scope of the examples described
herein.
[0030] As noted above, the systems and methods of the present disclosure
are
for use in the context of a thermal process for recovering hydrocarbons from a
subterranean reservoir. The thermal process may be for example a steam-
assisted
gravity-drainage (SAGD) process, a cyclic-steam-simulation (CSS) process, a
steam-
flooding (SF) process, a solvent-assisted-cyclic steam stimulation process, a
toe-to-
heel-air-injection (THAI) process, a solvent-aided process (SAP), a solvent-
driven
process (SDP), or a combination thereof (for example occurring at different
well pads
that feed into fluid handling processes and systems described herein). In
embodiments of the present disclosure wherein the hydrocarbon-recovery process
involves solvent injection, the produced-fluid stream may comprise solvent.
For
example, the produced-fluid stream may have a solvent:water ratio of up to
about 1:9
% on a weight basis. Solvent content in the produced-fluid stream may
influence the
processing parameters used during emulsion treating. In particular, the
emulsion-
treating sub-system may be configured to capitalize on density differences
between
oil-based and water-based phases to facilitate separation. As significant
solvent
content in the produced-fluid stream may impact the density of the oil-based
phase,
the occurrence of substantial solvent content in the produced-fluid streams
may
hinder oil-water separation (increasing solvent content may decrease the
difference
in densities between oil-based and water-based phases). Accordingly, in some
embodiments of the present disclosure, solvent may be removed prior to
emulsion
treating. Those skilled in the art, having benefited from the teachings of the
present
disclosure, will recognize the modulations required of the emulsion-treating
sub-
system to account for produced-fluid streams that comprise substantial volumes
of
solvent and/or the technologies available to separate solvent prior to
emulsion .
treatment.
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[0031] In the context of the present disclosure, the produced-fluid
stream may
be produced at a production temperature that is above 80 C, above 100 C, or
in
some cases significantly above 100 C, for example being at least 125 C, 150
C,
175 C, 200 C, or 225 C, or being within the range of from about 100 C to
250 C.
Typical temperatures for fluids produced during SAGD may for example be
between
about 150 C and 250 C, while other thermal-recovery processes, such as CSS,
may
produce fluids at temperatures from about 50 C to 250 C.
[0032] In the context of the present disclosure, the produced-fluid
stream may
have an oil:water ratio of between about 20:80 and about 90:10, or any ratio
between
these values. Those skilled in the art will recognize that such ratios
typically fluctuate
during production. In SAGD, this ratio may for example be from about 20:80 to
about
35:65. In SAP, this ratio may for example be from about 60:40 to about 90:10,
or for
example alternatively about 75:25 to about 90:10, depending on the amount of
solvent injected. These produced fluids are typically characterized by
relatively high
levels of dissolved and entrained materials, with the water portion for
example being
characterized by one or more parameters that may include between about 50 ppm
and about 4000 ppm total suspended solids, between about 50 ppm and about 400
ppm silica, between about 5 ppm and about 75 ppm hardness (or alternatively
between about 5 ppm and about 225 ppm hardness), and between about 30 ppm and
about 1000 ppm soluble organics (measured as total organic carbon), or a
combination thereof.
[0033] The systems/methods of the present disclosure comprise an
emulsion-
treating sub-system that is configured to separate the produced-fluid stream
into a
produced-oil stream and an oily produced-water stream.
[0034] In select embodiments of the present disclosure, the emulsion-
treating
sub-system may comprise an upside-down separator. In the upside-down
separator,
the processing temperature may be maintained at (or heated to) a relatively
high
level, for example in a range of between about 150 C and about 250 C to
provide a
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lower viscosity and a sufficient density difference between the oil and the
water to
effect gravity separation. Under such conditions, the hot emulsion may
separate with
the oil portion being more dense than the water portion, hence the term
"upside
down". The upside-down separator may be configured as an upside-down treater
(UDT). Those skilled in the art will recognize that an upside-down treater is
a
separator that is configured to provide a produced-oil stream that meets water-
content transportation specifications without additional processing.
[0035] In select embodiments of the present disclosure, the emulsion-
treating
sub-system may comprise a hot-cyclone separator. In the hot-cyclone separator,
the
produced-fluid stream emulsion may be maintained at (or heated to) a
relatively high
degree such as a temperature in a range of between about 180 C and about 230
C
to provide a lower viscosity and wider density difference between the oil and
the
water. This may allow for hot-emulsion separation with the oil portion being
heavier
than the water portion. The hot-cyclone separator may comprise a hot-
hydrocyclone
separator, a hot-oleocyclone separator, or a combination thereof (in that the
emulsion
treating sub-system may involve single or multiple stage separation). Cyclone
separators leverage differences in angular velocities of spinning fluids to
separate oil
and water (cyclones are for example described in the following patent
documents:
US 5,017,288; US 5,071,557; and US 5,667,686). The oil-water emulsion may be
degassed, prior to or in the absence of heating, and then may be pumped up to
a
higher pressure such as between about 1,500 kPag and about 2,500 kPag to
prevent
flashing in the cyclone. The emulsion may then enter the cyclone unit where
the
difference in density between the oil and the water may cause the heavier
product, in
this case oil, to coalesce on the outside of the cyclone, with the lighter
fluid, in this
case water, floating to the inside of the cyclone (in contrast to conventional
hydrocyclone separation). The oil may exit the cyclone via the tapered end
with the
water exiting via the overflow stream outlet. Each phase of the emulsion may
require
additional cyclonic steps to reach the desired product qualities for further
processing,
transportation, or disposal. Additionally, pumps may be required to overcome
the
pressure drop require for each cyclone stage.
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[0036] Regardless of whether the emulsion-treating sub-system
comprises an
upside-down separator or a hot cyclone separator, the emulsion-treating sub-
system
may reduce or eliminate the need for diluent and may reduce or eliminate the
need
for treatment chemicals as compared to conventional processes. Such as the one
.. shown in FIG. 1, wherein diluent addition is exemplified by an inlet to the
conventional
emulsion-treatment process 102.
[0037] Accordingly, the emulsion-treating sub-system may be suitable
for use
as component in a system for processing remote from a central processing
facility.
Moreover, the emulsion-treating sub-system may provide the produced-oil stream
with relatively little water inclusion and the oily produced-water stream with
relatively
little oil inclusion. The produced-oil stream may then be flashed in a flash
treater to
remove the remaining water to below 0.5 % basic sediment and water while
remaining
in, for example, the 130 C to 230 C temperature range. At the same time the
oily
produced-water stream may be maintained by the system at a baseline
temperature
.. of, for example, at least about 130 C, 150 C, 160 C, 170 C, 175 C, 180
C, 185
C, 190 C, 195 C, or 200 C in the absence of heating. Heating above this
baseline
temperature is optional. For example, the oily produced-water stream may be
maintained by the system at a temperature of between about 190 C and about
200
C and/or a pressure of between about 1 MPa and about 3.1 MPa. A heater used
for
heating may be, for example, an electric heater, an induction heater, an
infrared
heater, a radio-frequency heater, a microwave heater, a natural gas heater, a
circulating fluid heater, or a combination thereof. In the absence of this
optional
heating, the system is to maintain the oily produced-water stream close to or
above
this baseline temperature. Enthalpy maintenance sub-systems of the system may
for
example be adapted so that the temperatures and/or pressures maintained in the
emulsion-treating sub-system are kept within a particular degree of departure
from
the temperatures and/or pressures of the produced emulsion, for example within
a
variation of 20 %, 15 %, 10 % or 5 %. As such, an enthalpy maintenance sub-
system
may for example include insulation and other fluid handling adaptations that
maintain
the temperature and/or pressure of fluids within the system.
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[0038] The emulsion-treating sub-system may be configured to separate
a
high proportion of the oil, leaving the oily produced-water stream with a
relatively low
residual oil concentration, for example of less than about 10,000 ppm (such as
less
than about 2,000 ppm, in particular between about 10 ppm and about 200 ppm).
The
produced-oil stream may correspondingly have a relatively low basic sediment
and
water (BS&W) content, for example of less than 0.5 % to meet transportation
specifications. The oily produced-water stream may be maintained at elevated
temperatures and pressures within the system. Dissolved and entrained
materials in
the oily produced-water stream may be characterized as including: a total-
suspended-solids content of at least about 100 ppm; a turbidity of at least
about 250
NTU; a turbidity of less than about 1,000 ppm; a silica content of at least
about 20
ppm (such as at least about 250 ppm, or between about 50 ppm and about 400
ppm);
a hardness content of at least about 5 ppm (such as at least about 10 ppm, or
between about 5 ppm and about 225 ppm); a soluble organics content of between
about 30 ppm and about 400 ppm; or a combination thereof. In effect, the
dissolved
and entrained material that is quantified by these characteristics is
segregated
predominantly into the oily produced-water stream, as opposed to into the
produced-
oil stream. The degree of this segregation may be quantified, so that a select
proportion of the relevant chemical species segregates into the oily produced-
water
stream for each of the foregoing parameters. For example, at least 70 %, 75 %,
80
%, 85 %, 90 %, 95 % or 98 % of the total suspended solids, silica, hardness,
total
organic carbon, or a combination thereof, present in the produced-fluid stream
may
be segregated into the oily produced-water stream.
[0039] In the context of the present disclosure, the produced-oil
stream may
be discharged from the system, for example for transportation, upgrading,
and/or
sales storage. With respect to transportation, the produced-oil stream may be
blended and/or processed to meet transportation specifications such as
pipeline
specifications, railway specifications, truck specifications, or a combination
thereof.
Blending and/or processing of the produced-oil steam may occur proximate to
the
well pad or at a central processing facility. With respect to upgrading,
residual heat
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present in the produced-oil stream may be capitalized on to reduce the energy
input
required to achieve the elevated temperatures and pressures used to upgrade
the
produced-oil stream. Upgrading the produced-oil stream may for example involve
one
or more viscosity and/or density reduction processes, for example involving
chemical
(e.g., hydrocracking/hydrotreating), thermal (coking/visbreaking) or physical
(separation) treatments, such as those involving cavitation (optionally
involving
reactive co-feeds or conventional or enhanced thermal techniques such as
coking or
visbreaking; see for example the following patent documents: CA 2,611,251; CA
2,617,985; CA 2,858,705; and CA 2,858,877). At the central processing
facility, the
produced-oil stream may be fed directly into a partial-upgrading system where
it may
be heated and fractionated to enhance the process or recover lighter ends or
diluent.
Partial upgrading may improve oil properties, for example, density, viscosity,
asphaltenes content, total acid number, sulfur content, or a combination
thereof, and
partial upgrading may be used to help meet oil transportation (e.g., pipeline,
truck,
and/or railway) specifications. The produced-oil stream may be further heated
at the
central processing facility to above about 350 C and the oil may be partially
upgraded, for instance, by converting longer heavy oil chains into smaller
chains.
Those skilled in the art will recognize that such processes may lower the
viscosity of
the resulting partially-upgraded oil compared to the oil that entered the
partial-
upgrading system. The oil may then be fractionated and the lighter fractions
hydro-
polished to reduce olefins below typical pipeline specifications of 1 %.
Partial-
upgrading processes may involve cavitation, shearing, thermal cracking and/or
catalyst enhanced upgrading (in general terms, including for example mild
thermal
cracking such as visbreaking or mild coking, which may include enhancements
such
as the use of shearing, cavitation, or co-reactants).
[0040] In the context of the present disclosure, the oily produced-
water may be
further de-oiled and/or treated in a de-oiling process to reduce residual-oil
content,
silica content, hardness content, total-suspended-solids content, soluble-
organics
content, and/or turbidity. As noted above, conventional processes de-oil and
treat
water below 100 C, because they rely on equipment that is not amenable to
high
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temperature and/or high pressure processing. As a first example, conventional
water-
treatment tanks must operate at temperatures below the boiling point of their
contents
in order to ensure containment. As a second example, conventional hardness-
removal technologies (e.g. ion-exchange units) typically rely on hardness
removal
resins that degrade at higher temperatures. In contrast, the systems/methods
of the
present disclosure utilize a de-oiling sub-system that is operable at high-
temperature
and high pressure and that does not require at least some of the additional
equipment
associated with conventional water treatment (such as the acid tanks and
caustic
tanks associated with ion-exchange units). As such the de-oiling sub-system of
the
present disclosure may occupy a modest footprint as compared to a traditional
water-
treating system at a central processing facility, and the de-oiling sub-system
may be
modular, portable, and/or upgradable
[0041] In select embodiments of the present disclosure, the de-oiling
sub-
system comprises a flotation-type unit. Flotation-type units are advantageous
in the
context of the present disclosure, because flotation is typically performed in
vessels
that may be designed to operate within a wide range of conditions (including
high-
temperature and high-pressure conditions). In select embodiments of the
present
disclosure, the flotation-type unit may be a compact flotation unit (CFU), a
traditional
multi-stage horizontal flotation unit, a single-stage flotation unit, or a
combination
thereof. Those skilled in the art will recognize that a compact flotation unit
typically
comprises a multi-stage (typically vertical) vessel with swirling/cyclonic
separation
enhancement (see Advances in Compact Flotation Units (CFUs) for Produced Water
Treatment by Bhatnagar, M. & Sverdrup, C. J. Offshore Technology Conference
Asia
held in Kuala Lumpur, Malaysia, 25-28 March 2014 (OTC-24679-MS)). De-oiling
via
.. a flotation-type unit may be aided by the addition of a density-reducing
agent (i.e. a
light hydrocarbon or other chemical agent capable of reducing the density of
an oil
phase in the oily produce-water stream). The density-reducing agent may be
oleophilic and/or hydrophobic such that it forms a single phase with residual
oil in the
oily produced-water stream. The density-reducing agent may have a density,
which
is lower than that of the residual oil in the oily-produced water stream such
that
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addition of the density-reducing agent may aid in oil-water separation by
increasing
the floatability of the oil phase. For example, the density-reducing agent may
be a
pentane-rich natural gas liquid.
[0042] In select embodiments of the present disclosure, the de-oiling
sub-
system comprises a filtration-type unit. Filtration-type units are
advantageous in the
context of the present disclosure, because filtration-type units may be
configured to
accommodate a wide variety of operating conditions (including high-temperature
and
high-pressure conditions). In select embodiments of the present disclosure,
the
filtration-type unit comprises a filter press, a traditional filter, a
membrane filter, or a
combination thereof. Filtration units are further described in the following
patent
documents: US 6,180,010; US 5,437,793; US 5,698,139; US 5,837,146; US
5,961,823; and US 7,264,722.
[0043] Regardless of whether the de-oiling sub-system comprises a
flotation-
type unit or filtration-type unit, the de-oiling sub-system may be configured
to de-oil
the oily produced-water stream such that the de-oiled water stream has: a
residual
oil content of less than about 25 ppm (such as less than about 20 ppm, 15 ppm,
10
ppm, or 5 ppm); a total-suspended-solids content of less than about 900 ppm
(such
as less than 5 ppm, or between about 50 ppm and about 900 ppm); a turbidity of
less
than about 10 NTU; a silica content of at least 50 ppm (such as between about
50
, ppm and about 400 ppm); a hardness content of at least 5 ppm (such as
between
about 5 ppm and 225 ppm, in particular between about 5 ppm and about 15 ppm);
a
soluble organics content of less than about 700 ppm (such as between about 30
ppm
and about 700 ppm, in particular between about 30 ppm and about 400 ppm); or a
combination thereof. In select embodiments, the de-oiled water stream may for
.. example have residual total suspended solids, silica, hardness, and total
organic
carbon values within a preferred degree of variance from the values of the
produced
water stream, for example within 5 %, 10 %, 15 %, 20 %, 25 % or 30 % of the
total
suspended solids, silica, hardness, and/or total organic carbon values of the
oily
produced-water stream.
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[0044] In select embodiments of the present disclosure, make-up water
may
be added to the de-oiled-water stream to produce an input stream for a steam-
generating-sub-system. As will be appreciated by those skilled in the art,
make-up
water may comprise one or more dissolved or entrained materials. For example,
brackish make-up water may have a silica content of between about 0.1 ppm and
about 200 ppm, a hardness content of between about 10 ppm and about 1000 ppm,
and a total-dissolved-solids content of between about 100 ppm and about 15000
ppm.
The make-up water may be combined with the de-oiled-water stream in equipment
such as piping, a tank, a vessel, or a combination thereof. Prior to combining
the
make-up water with the de-oiled-water stream, the make-up water may be
processed
and/or handled to ensure that the steam-generating-sub-system input stream has
average residual-oil concentration of less than about 25 ppm, an average
silica
content of at least about 20 ppm, and an average hardness content of at least
about
5 ppm. For example, the make-up water may be filtered, exposed to ion
exchange,
stored in a holding tank or a surge tank, pumped through a heat exchanger to
either
increase or decrease the make-up water temperature, or a combination thereof.
Heat
exchange between the make-up water and at least one of blowdown, sales oil, or
other process facility fluid streams may contribute to the energy efficiency
of the
method of processing fluids as described herein. Alternatively, heat exchange
with
the make-up water may be facilitated via a glycol system, a cooler, or any
other
suitable heat exchange process as will be understood by those skilled in the
art.
[0045] In the context of the present disclosure, the steam-generating-
inlet
stream may comprise fluids from the de-oiled-water stream (A) and fluids from
the
make-up-water stream (B). The volume ratio of these components (A:B) may vary.
For example, the volume ratio (A:B) may be between about 40:60 and about
100:0.
The volume ratio (A:B) may be modulated to accommodate parameters associated
with production from the reservoir. In particular, the volume ratio (A:B) may
be
modulated to account for changes in the steam-to-oil ratio (SOR), the produced-
water-to-steam ratio (PWSR), steam quality, or a combination thereof. The
volume
ratio (A:B) may also be modulated to account for water entrained in the
produced-oil
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stream (intended to maintain water as the continuous phase for transportation
to
sales oils tanks). For example, for a process providing a SOR of about 1.8, a
PWSR
of about 0.95, a steam quality of about 75 %, and a 20 % water diversion to
the
produced-oil stream, make-up water may account for about 40 % of the steam-
generating input stream. As a further example, for a process providing an SOR
of
about 3.0, a PWSR of about 1.15, a steam quality of about 75 %, and a 20 %
water
diversion to the produced-oil stream, make-up water may account for about 20
A) of
the steam-generating input stream. Those skilled in the art will recognize
that PWSR
of greater than one may occur when hydrocarbon production is executed on a
reservoir that contains substantial amounts of connate water. Those skilled in
the art,
having benefited from the teachings of the present disclosure will recognize
how to
achieve a suitable volume ratio (A:B) for the inlet stream in view of the
relevant
process parameters and having regard to the particular water-chemistry
specifications set out herein for the inlet stream to the steam-generating sub-
system.
In the context of the present disclosure, the de-oiled-water stream and the
steam-
generating-sub-system input fluid stream may for example be maintained by the
system at a baseline temperature and/or pressure. For example, the base-line
temperature may be, for example, at least 100 C, 125 C, 150 C, 160 C, 170
C or
175 C in the absence of heating and the baseline pressure may be, for
example,
between about 1 MPa and about 3.1 MPa. Optionally, the input stream for the
steam-
generation sub-system may be heated above the baseline input temperature; in
the
absence of this optional heating, the system may be constructed and operated
so
that it maintains the fluids undergoing processing in the fluid handling
system above
the baseline steam generator input temperature. The enthalpy maintenance sub-
systems of the system, for example temperature maintenance systems, such as
insulation, and/or pressure containment systems, such as pressure vessels, may
for
example be adapted so that in the process of producing the input fluid stream,
temperatures and/or pressures are maintained within a particular degree of
departure
from the temperatures and/or pressures of the de-oiling sub-system, for
example
within a variation of 20 %, 15%, 10% or 5 %.
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[0046] In select embodiments of the present disclosure, produced-
fluid-
recycling efficiencies are provided by the system, so that the volume ratio of
oily
produced-water stream to the input stream of the steam-generating sub-system
is
relatively high, representing for example at least 75 %, 80 %, 85 %, 90 % or
95 %
produced water reuse for steam generation. In essence, as much of the oily
produced-water stream as practical moves forward for use as the steam
generator
input fluid stream. Similarly, the system may be adapted to maintain a
relatively high
ratio of treated water volume to make-up water volume, for example of at least
6:4,
7:3, 8:2 or 9:1, representing for example at least 60 % of the treated water
volume
being used for steam generation along with 30 % make-up water. The enthalpy
maintenance sub-systems of the fluid handling system may be adapted to
maintain
the steam generator input temperature within a desired range of the produced
emulsion temperature, in the absence of optional heating by the system, for
example
within 50 C, 40 C, 30 C or 20 C.
[0047] In the context of the present disclosure the steam-generating sub-
system may comprise any of a variety of steam generating technologies provided
the
steam-generating sub-system is operable to generate steam having an average
quality of at least about 75 % from an input stream that comprises fluid from
the de-
oiled-water stream, wherein the input stream has an average residual-oil
concentration of less than about 25 ppm, an average silica content of at least
about
50 ppm, and an average hardness content of at least about 5 ppm, and wherein:
(i)
the system is configured to maintain the temperature of the input stream above
the
normal boiling point thereof, and (ii) the system is configured to maintain
the pressure
of the input stream above ambient atmospheric pressure.
[0048] As a first non-limiting example, the steam-generating sub-system may
comprise a flash steam generator. The Flash steam generator may be made up of
a
fired heater and a flash vessel. The steam generator input fluid, which may
include
de-oiled water and make-up water, may be pumped to high pressures, for example
from 10 MPa to 20 MPa, heated to above the desired flash point without
creating a
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steam substantial fraction, for example at about 300 C to 400 C, and flashed
in a
flash vessel to create a steam fraction, for example of 20 to 40 % steam
quality. From
this, dry steam may be injected into the reservoir for thermal hydrocarbon-
recovery
processes, while the remaining liquid fraction (blowdown) may be re-
pressurized,
filtered, and recombined with the steam generator input fluid stream. In this
way, the
overall steam-generating process may produce a dry steam fraction for use in
hydrocarbon recovery and a liquid blowdown that may be disposed of, or
recycled
back into the steam generator input fluid stream.
[0049] As a second non-limiting example, the steam-generation sub-
system
may comprise an ultra-low-quality (ULQ) steam-generation sub-system as
describe
in Canadian patent application number 2,978,237. ULQ steam-generation sub-
systems are capable of operating with feed streams having impurity levels that
are
orders of magnitude greater than what is traditionally considered feasible by
industry
and boiler manufacturers due at least in part to their inlet-stream
velocities. For
.. example, the inlet stream for a ULQ steam generation sub-system may for
example
have a silica content of greater than about 150 mg/L and a total hardness of
greater
than about 10 mg/L. In some embodiments of the present disclosure, the steam
portion of the ULQ steam generator outlet stream may be between about 10 % and
about 50 % of the outlet stream by mass (i.e. a steam quality of between about
10 A)
and about 50 %). In other embodiments the steam portion of the outlet stream
may
be between about 20 % and about 40 % of the outlet stream by mass. The stream
produced at the outlet of the ULQ steam generator may thus be a wet steam
stream
having a relatively low steam quality. A steam separator may accordingly be
provided
as part of the ULQ steam-generation sub-system. The steam separator may have
an
inlet, a steam outlet, and a recirculation-stream outlet. The steam separator
may be
operable to separate at least a portion of a remaining liquid phase portion
from the
outlet stream to produce a recirculation stream at the recirculation stream
outlet.
Separation of liquid phase portions of the outlet stream increases a mass
proportion
of the steam portion in the outlet stream at the steam outlet to have an
increased
steam proportion by mass. A recirculation line may be provided to recirculate
a
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recirculation stream from the recirculation stream outlet back to the steam
generator
input fluid. The recirculation stream would typically have a temperature above
100
C, and optionally a temperature in a range of about 220 C to about 270 C. A
relatively, high fluid flow rate within the ULQ steam-generation sub-system
may be
used to provide increased velocity-head values (wherein velocity-head = 1/2pv2
wherein p is fluid density, and v is fluid-flow speed at a point within flow
line as used
in Bernoulli's equation) within the fluid flow, which may reduce the
propensity for
impurities in the feedwater to cause scaling within the ULQ steam-generation
sub-
system. Examples of empirically determined bounds for 1/2pv2 would be a
minimum
of about 10,000 Ibft-1s-2 and a maximum of about 60,000 1bft-1s-2 (in
particular
between about 10,000 lbft-15-2 and about 30,000 1bft-1s-2). The operating
parameters
of flow rate, firing rate, and steam quality are thus selected to operate the
ULQ steam-
generation sub-system within a desired 114pv2range and for a targeted steam
production at the steam outlet. When the flow rate at which the feedwater
stream is
delivered is selected as described, a substantial portion of impurities remain
in
solution in the liquid phase portion thus reducing scaling within the ULQ
steam-
generation sub-system. In some embodiments, the proportion of impurities
remaining
in solution in the liquid phase may for example be between about 50 % and
about
100 % (in particular between about 50 % and about 90 %).
[0050] The steam-generating sub-system may further comprise a recirculation
loop to recirculate liquids, vapours, or a combination thereof from an outlet
of the
steam separator to the input to the steam-generating sub-system.
[0051] Regardless of the particulars of the steam-generation sub-
system, the
steam may have a quality on the order of at least 75 %, 80 %, 85 %, 90 % or 95
%
steam quality. This steam may then be delivered by the system to a well head
for
injection into the reservoir, with the fluid handling system constructed and
operated
so as to preserve steam quality so that the injected steam has a quality
within 5 % of
the steam quality of the outlet stream of the steam generator or the steam
separator,
being for example at least 70 %, 75 %, 80 %, 85 % or 90 %. In this context,
steam
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quality refers to an average steam quality over a period of time, for example
a day, a
week, a month or a year. It will typically be the case that there are
intervals within
such periods during which steam quality deviates significantly from the
average
value, for example falling significantly below the average steam quality
achieved in
processes described herein.
[0052] FIG. 2 is a schematic illustration of a first shortened-path
produced-fluid
processing and steam-generation process in accordance with the present
disclosure.
The shortened-path produced-fluid processing and steam-generation process
includes an upside down separator as the emulsion-treating sub-system, a
flotation-
type unit (e.g. a compact flotation unit (CFU)) as the de-oiling sub-system,
and a flash
steam generator as the steam generating sub-system. Of course, the steam-
generating sub-system may alternatively be a ULQ steam-generation sub-system
or
any other steam-generation sub-system that is operable to generate steam
having an
average quality of at least about 75% from an input stream that comprises
fluid from
the de-oiled-water stream, wherein the input stream has an average residual-
oil
concentration of less than about 25 ppm, an average silica content of at least
about
50 ppm, and an average hardness content of at least about 5 ppm, and wherein:
(i)
the system is configured to maintain the temperature of the input stream above
the
normal boiling point thereof, and (ii) the system is configured to maintain
the pressure
of the input stream above ambient atmospheric pressure.
[0053] FIG. 3 is a schematic illustration of a second shortened-path
produced-
fluid processing and steam-generation process in accordance with the present
disclosure. The fluid-processing system includes a hot-cyclone separator as
the
emulsion-treating sub-system, a filtration-type unit as the de-oiling sub-
system, and
a ULQ steam-generation sub-system as the steam-generating sub-system. Of
course, the steam-generating sub-system may alternatively be a flash steam
generator or any other steam-generation sub-system that is operable to
generate
steam having an average quality of at least about 75% from an input stream
that
comprises fluid from the de-oiled-water stream, wherein the input stream has
an
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average residual-oil concentration of less than about 25 ppm, an average
silica
content of at least about 50 ppm, and an average hardness content of at least
about
ppm, and wherein: (i) the system is configured to maintain the temperature of
the
input stream above the normal boiling point thereof, and (ii) the system is
configured
5 to maintain the pressure of the input stream above ambient atmospheric
pressure.
[0054] In select implementations of embodiments of the present
disclosure,
such as those shown in FIG. 2 and FIG. 3, a demulsifier and/or a reverse
emulsion
breaker may for example be added upstream of the emulsion-treating sub-system.
In
addition, a clarifier may be added to the inlet or oily-produced-water outlet
of the
emulsion-treating sub-system. A pH adjustment may take place, for example at
the
inlet of a boiler-feed water surge vessel in the steam-generating sub-system.
For
corrosion control, an amine inlet may for example be included in the steam
line out of
the steam-generating sub-system. For example, amine in liquid or solution form
may
be stored in a tank and introduced (added) into the steam line by pumping
through
an injection quill.
[0055] In select implementations of the illustrated processes of FIG.
2 and/or
FIG. 3, operating temperatures in the system may be in the range of about 130
C-
220 C, throughout the train of treatment steps, with that temperature
maintained
through the emulsion-treating, de-oiling, and steam-generating sub-processes
to '
capitalize on greater fluid density differences at higher processing
temperatures. This
phenomena is exemplified by the plot illustrated in FIG. 4, which provides
empirically
determined fluid density values as a function of temperature for 9.40 API raw
bitumen
and water at 1800 kPa. In the context of FIG. 4, it is apparent that the
difference
between the fluid density of the water sample and the fluid density of the
bitumen
increases with increasing temperature beyond an equivalence point at about 130
C.
This may allow the relatively hot emulsion to separate with the oil portion
being
heavier than the water portion. The emulsion separation may require reduced or
no
diluent and reduced or no treatment chemicals to produce semi-dry oil and de-
oiled
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produced water streams (for example the process may be carried out without a
demulsifier).
[0056] In select embodiments of the present disclosure, the steam
generating
input fluid stream may be characterized as having an oil and grease content of
.. between about 1 ppm and about 5 ppm, a silica content of between about 100
ppm
and about 250 ppm, and a hardness content of between about 15 ppm and about
200
ppm.
[0057] In select embodiments of the present disclosure, a surge
vessel may
be used to dampen changing flow rates of steam generator input fluid into the
steam-
generating sub-system. The boiler-feed water (which may include both treated
water
and make-up water) may be pumped to high pressures, for example from 10 MPag
to 20 MPag, heated to above the desired flash point without creating a steam
fraction
at about 300 C to 400 C, and flashed in a flash vessel to create a steam
fraction of
between about 20 % and about 40 % steam quality. This dry steam may be
injected
into the reservoir for thermal hydrocarbon-recovery processes, while a portion
of the
remaining liquid fraction (i.e. blowdown) may be re-pressurized, filtered, and
recombined with the boiler-feed-water stream. The overall steam-generation
process
will produce a dry steam fraction for use in hydrocarbon recovery and a liquid
blowdown that may be disposed of.
[0058] In alternative embodiments of the present disclosure, solvents (for
example, propane or butane) may be injected into the steam-generating and
handling
systems associated with the facilities described herein, to aid in the thermal
hydrocarbon-recovery process via, for example, co-injection of a solvent with
steam
in a solvent-aided process (SAP). Solvent may for example be co-injected with
steam
into an injection well, and this solvent may be added to injection fluids
within the
systems disclosed herein. In this way, a thermal recovery fluid is provided
that
comprises a solvent. Propane, butane, or alternative solvents may be supplied
directly for a SAP (e.g. from a solvent bullet). In alternative embodiments,
the solvent
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may for example be a light hydrocarbon solvent, selected on the basis that it
is
miscible with, and capable of enhancing the mobility of, the reservoir
hydrocarbons.
As such, the solvent may be deployed as a mobilizing fluid, comprising for
example
one or more C3 through Cio linear, branched, or cyclic alkanes, alkenes, or
alkynes,
in substituted or unsubstituted form, or other aliphatic or aromatic
compounds. Select
embodiments may for example use an n-alkane as the dominant component, for
example propane or n-butane.
[0059] In the present disclosure, all terms referred to in singular
form are meant
to encompass plural forms of the same. Likewise, all terms referred to in
plural form
are meant to encompass singular forms of the same. Unless defined otherwise,
all
technical and scientific terms used herein have the same meaning as commonly
understood by one of ordinary skill in the art to which this disclosure
pertains.
[0060] In the context of the present application, various terms are
used in
accordance with what is understood to be the ordinary meaning of those terms.
For
example, "petroleum" is a naturally occurring mixture consisting predominantly
of
hydrocarbons in the gaseous, liquid or solid phase. In the context of the
present
application, the words "petroleum" and "hydrocarbon" are used to refer to
mixtures of
widely varying composition. The production of petroleum from a reservoir
necessarily
involves the production of hydrocarbons, but is not limited to hydrocarbon
production
and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu,
and/or V).
Similarly, processes that produce hydrocarbons from a well will generally also
produce petroleum fluids that are not hydrocarbons. In accordance with this
usage, a
process for producing petroleum or hydrocarbons is not necessarily a process
that
produces exclusively petroleum or hydrocarbons, respectively. "Fluids", such
as
petroleum fluids, include both liquids and gases. Natural gas is the portion
of
petroleum that exists either in the gaseous phase or in solution in crude oil
in natural
underground reservoirs, and which is gaseous at atmospheric conditions of
pressure
and temperature. Natural gas may include amounts of non-hydrocarbons.
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[0061] It is common practice to categorize petroleum substances of
high
viscosity and density into two categories, "heavy oil" and "bitumen". For
example,
some sources define "heavy oil" as a petroleum that has a mass density of
greater
than about 900 kg/m3. Bitumen is sometimes described as that portion of
petroleum
that exists in the semi-solid or solid phase in natural deposits, with a mass
density
greater than about 1,000 kg/m3 and a viscosity greater than 10,000 centipoise
(cP;
or 10 Pa's) measured at original temperature in the deposit and atmospheric
pressure
on a gas-free basis. Although these terms are in common use, references to
heavy
oil and bitumen represent categories of convenience, and there is a continuum
of
properties between heavy oil and bitumen. Accordingly, references to heavy oil
and/or bitumen herein include the continuum of such substances, and do not
imply
the existence of some fixed and universally recognized boundary between the
two
substances. In particular, the term "heavy oil" includes within its scope all
"bitumen"
including hydrocarbons that are present in semi-solid or solid form.
[0062] A "reservoir" is a subsurface formation containing one or more
natural
accumulations of moveable petroleum, which are generally confined by
relatively
impermeable rock or other geological feature. An "oil sand" or "oil sands"
reservoir is
generally comprised of strata of sand or sandstone containing petroleum.
"Thermal
recovery" or "thermal stimulation" refers to enhanced oil recovery techniques
that
involve delivering thermal energy to a petroleum resource, for example to a
heavy oil
reservoir. There are a significant number of thermal recovery techniques other
than
SAGD, such as cyclic steam stimulation (CSS), Solvent-aided processes (SAP),
solvent-driven processes (SDP), in-situ combustion, hot water flooding, steam
flooding and electrical heating. In general, thermal energy and/or a viscosity-
reducing
agent is provided to reduce the viscosity of the petroleum to facilitate
production. This
thermal energy may be provided by a "thermal recovery fluid", which is
accordingly a
fluid that carries thermal energy, for example in the form of steam or
solvents or
mixtures thereof, with or without additives such as surfactants.
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A8141898CA
[0063] As used herein, the term "about" refers to an approximately +/-
10 %
variation from a given value. It is to be understood that such a variation is
always
included in any given value provided herein, whether or not it is specifically
referred
to.
[0064] It should be understood that the compositions and methods are
described in terms of "comprising," "containing," or "including" various
components
or steps, the compositions and methods can also "consist essentially of or
"consist of
the various components and steps. Moreover, the indefinite articles "a" or
"an," as
used in the claims, are defined herein to mean one or more than one of the
element
that it introduces.
[0065] For the sake of brevity, only certain ranges are explicitly
disclosed
herein. However, ranges from any lower limit may be combined with any upper
limit
to recite a range not explicitly recited, as well as, ranges from any lower
limit may be
combined with any other lower limit to recite a range not explicitly recited,
in the same
way, ranges from any upper limit may be combined with any other upper limit to
recite
a range not explicitly recited. Additionally, whenever a numerical range with
a lower
limit and an upper limit is disclosed, any number and any included range
falling within
the range are specifically disclosed. In particular, every range of values (of
the form,
"from about a to about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be understood
to set
forth every number and range encompassed within the broader range of values
even
if not explicitly recited. Thus, every point or individual value may serve as
its own
lower or upper limit combined with any other point or individual value or any
other
lower or upper limit, to recite a range not explicitly recited.
[0066] Therefore, the present disclosure is well adapted to attain the ends
and
advantages mentioned as well as those that are inherent therein. The
particular
embodiments disclosed above are illustrative only, as the present disclosure
may be
modified and practiced in different but equivalent manners apparent to those
skilled
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A8141898CA
in the art having the benefit of the teachings herein. Although individual
embodiments
are discussed, the disclosure covers all combinations of all those
embodiments.
Furthermore, no limitations are intended to the details of construction or
design herein
shown, other than as described in the claims below. Also, the terms in the
claims
have their plain, ordinary meaning unless otherwise explicitly and clearly
defined by
the patentee. It is therefore evident that the particular illustrative
embodiments
disclosed above may be altered or modified and all such variations are
considered
within the scope and spirit of the present disclosure. If there is any
conflict in the
usages of a word or term in this specification and one or more patent(s) or
other
.. documents that may be referenced herein, the definitions that are
consistent with this
specification should be adopted.
[0067] Many obvious variations of the embodiments set out herein will
suggest
themselves to those skilled in the art in light of the present disclosure.
Such obvious
variations are within the full intended scope of the appended claims.
31
Date Recue/Date Received 2021-03-16
