Note: Descriptions are shown in the official language in which they were submitted.
PROCESSES FOR TREATING HYDROCARBON RECOVERY PRODUCED FLUIDS
FIELD OF THE INVENTION
[0001] The present disclosure is in the field of thermal hydrocarbon
recovery
processes, such as steam-assisted gravity drainage (SAGD) processes in heavy
oil
reservoirs. In particular, facilities for high temperature processing of
emulsions for water
reuse.
BACKGROUND
[0002] Some subterranean deposits of viscous hydrocarbons can be extracted
in-situ
by lowering the viscosity of the petroleum to mobilize it so that it can be
moved to, and
recovered from, a production well. Reservoirs of such deposits may be referred
to as
reservoirs of heavy hydrocarbons, heavy oil, bitumen, oil sands, or
(previously) tar
sands. The in-situ processes for recovering oil from oil sands typically
involve the use
of multiple wells drilled into the reservoir, and are assisted or aided by
thermal recovery
techniques, such as injecting a heated fluid, typically steam, into the
reservoir from an
injection well. One process of this kind is steam-assisted gravity drainage
(SAGD).
[0003] The SAGD process is in widespread use to recover heavy hydrocarbons
from
the Lower Cretaceous McMurray Formation, within the Athabasca Oil Sands of
northeastern Alberta, Canada. The geology of this region is emblematic of the
geological complexities associated with many heavy oil bearing formations. In
general
terms, a thick sequence of marine shales and siltstones of the Clearwater
Formation
unconformably overlies the McMurray Formation in most areas of northeastern
Alberta.
In some areas, glauconitic sandstones of the Wabiskaw member are present at
the
base of the Clearwater. The Grand Rapids Formation overlies the Clearwater
Formation, and quaternary deposits unconformably overlie the Cretaceous
section. The
pattern of hydrocarbon deposits within this geological context is accordingly
complex
and varied. This geologic complexity gives rise to challenges in handling
fluids produced
in SAGD processes, because these produced fluids may contain a very wide range
of
dissolved solids and other materials derived from the reservoir undergoing the
hydrocarbon recovery process.
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[0004] In a typical SAGD process, as for example disclosed in Canadian
Patent No.
1,130,201 issued on 24 August 1982, hydrocarbons are recovered along with
significant
volumes of produced water (or production water). There are advantages
associated with
recycling produced water for steam generation. However, these advantages may
be
offset by challenges associated with the necessity to treat produced water so
as to
obtain a treated water that is suitable for use in steam generation. In
particular,
recycling of produced water has typically required overall removal of
suspended solids,
dissolved solids and of scale-forming chemicals, among other ions and chemical
compounds, that affect the operation of steam generating systems. Conventional
processes used to achieve appropriate degrees of water treatment may be
complex and
expensive. It may also be challenging to manage these processes as the
composition of
a produced water stream changes over time. It is also inefficient to cool the
process
water to fit in with conventional processing.
[0005] Produced water is typically received at a relatively high
temperature and
pressure, both of which must currently conventionally be reduced before the
produced
water is treated. For this reason, produced water treatment typically involves
the use of
heat exchangers to reduce the temperature of the produced water before
treatment to
remove oil and emulsions, suspended solids, dissolved solids and scale-forming
chemicals such as calcium, magnesium and silica. For recycling, treated water
is then
conventionally re-heated and re-pressurized in advance of steam generation,
with water
entering a steam generator characterized as boiler feed water (BFVV) having
relatively
stringent limits on entrained and dissolved materials so as to minimize scale
formation.
The cooling and re-heating and the re-pressurization of the treated water
represents a
significant proportion of the overall energy consumption of a SAGD process.
[0006] A conventional process for separating produced emulsion for oil
sales and
further water treatment involves a number of distinct steps, as follows. Oil-
water
emulsion from the reservoir may vary in temperature, for example from 80 C-250
C,
more typically 180 C-220 C, and with a pressure of about 1,200-2,000 kPag.
After
emulsion is recovered from the reservoir it may be degassed and then cooled to
130 C-
140 C to allow for diluent aided separation. The cooled emulsion is then
treated for
coarse oil-water separation, for example in free-water knock out (FWKO)
unit(s), and/or
other emulsion treaters, typically operating at about 800-1,500 kPag and 130 C-
140 C
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for traditional gravity separation, or alternatively operating at much lower
pressures of
between 100-800 kPag and 130 C-140 C for flash treating. These conventional
emulsion treating systems typically use diluent to aid in separation of oil
and water,
where the diluent is traditionally a pentane rich natural gas liquid (NGL) or
a synthetic
crude oil, and where the diluent remains in the dewatered oil that is then
cooled and
sent to sales oil tanks.
[0007] A conventional process for treating produced water for re-use in
steam
generation involves a number of distinct steps, as follows. Conventionally,
produced
water from emulsion treatment is cooled, using for example one or more heat
exchangers, before it is subjected to de-oiling and further water treatment.
This heat
exchange process may for example decrease the produced water temperature from
130 C-140 C to 80 C-95 C. De-oiling typically comprises several units, such as
a skim
tank for bulk oil separation, a floatation type unit such as an induced gas or
induced
static floatation unit (IGF/ISF) for further removal of oil and suspended
solids, and a
filtration type unit such as an oil removal filter (ORF). Subsequent water
treatment
typically includes, for example, a warm lime softener (WLS), which increases
the pH of
the water and adds MagOx (Magnesium Oxide) to remove silica. The WLS is
typically
followed by an ion exchange unit where removal of scaling ions occurs. Scaling
ions
typically include dissolved calcium, magnesium, lithium and iron. 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. Typical water quality from de-
oiling and
water treatment may be less than 50 ppm silica, less than 0.1 ppm hardness,
and less
than 1 ppm oil.
[0008] A conventional system for steam generation using treated produced water
involves a number of distinct steps including pre-heating through heat
exchangers, or
an alternative process of heat exchange, which typically increases the boiler
feed water
(BFW) temperature to between about 160 C and 220 C as a water inlet
temperature
prior to the steam generator. The pre-heated BFW typically enters an
economizer
section which further heats the BFW using convection from flue gas and then
the BFW
enters the fired section of the boiler. Conventional OTSGs (Once Through Steam
Generators) typically produce from 75-90% steam quality at pressures between 7
and
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15 MPa depending on the thermal reservoir requirements. The steam may then be
separated into dry steam and a liquid fraction containing impurities, which is
typical for
SAGD but not for all thermal in-situ processes, with the dry steam sent to one
or more
well heads or well pads for use in the reservoir during the hydrocarbon
recovery
process. Dry refers to steam at a very high steam quality of about 95% or
higher. The
liquid fraction separated from the generated steam (referred to as boiler
blowdown) is
sent for recycling or disposal.
[0009] A conventional system for treating recovered heavy oil (once
dewatered as
described above) involves blending with a hydrocarbon diluent, which may be
for
example a natural gas condensate, a synthetic hydrocarbon blend, naphtha,
butane, or
any combination thereof, to meet shipping specifications, primarily viscosity
and density
of the sales oil product.
[0010] 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, 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. The abbreviation POIP stands for
"producible oil
in place" and in the context of the methods disclosed herein is generally
defined as the
exploitable or producible oil structurally located above the production well
elevation.
[0011] It is common practice to categorize petroleum substances of high
viscosity
and density into two categories, "heavy oil" and "bitumen". For example, some
sources
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CA 3016971 2018-09-07
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.$)
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.
[0012] A "reservoir" is a subsurface formation containing one or more
natural
accumulations of moveable petroleum, which are generally confined by
relatively
impermeable rock. 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), in-situ combustion, hot water flooding, steam flooding and electrical
heating. In
general, thermal energy 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.
SUMMARY
[0013] Processes and systems are provided for integrating the main areas of
a
hydrocarbon recovery produced fluid processing facility to reduce equipment
and
increase efficiencies. In select processes and systems, conventional or
alternative
emulsion treating techniques, such as upside down treating or
condensate/propane as
diluent treating, may allow for a hot dewatered oil that can flow directly to
a partial
upgrading solution, such as viscosity reduction by thermal cracking, shearing
or
CA 3016971 2018-09-07
catalytic conversion processes. Concurrently the produced water from emulsion
treating may be kept at emulsion treating pressure and temperature to reduce
the
required equipment and associated facility space. This pressurized treated
produced
water may then flow into various alternative steam generation configurations
that are
advantaged by the higher temperature feed, and may be adapted so as not to
require
the inlet water quality of conventional systems.
[0014] Methods and systems are accordingly provided for processing fluids
for use in
a subterranean thermal hydrocarbon recovery process, wherein the method is
carried
out in an interconnected and contained fluid handling system operating above
atmospheric pressure. These methods and systems may include steps, or means
for, a
succession of treatments, including: producing an oil-water emulsion;
separating the
produced emulsion into a produced oil stream and an oily produced water
stream; de-
oiling and treating the oily produced water stream; adding make up water to
the treated
water; generating steam; and, injecting a thermal recovery fluid.
[0015] Steps involved in producing an oil-water emulsion from a hydrocarbon
reservoir undergoing the thermal recovery process, may for example include
producing
the emulsion at a production temperature above about 100 C. The oil:water
ratio of the
emulsion may for example be between about 20:80 and about 90:10.
[0016] Steps involved in separating the produced emulsion into a produced
oil
stream and an oily produced water stream may be carried out in an emulsion
treating
module. In this module, the produced oil stream may for example have a basic
sediment
and water content of less than about 0.5%, wherein the fluid making up the
oily
produced water stream is maintained by the fluid handling system at a
temperature of at
least about 100 C in the absence of heating. The oily produced water may for
example
have: a residual oil content of less than about 10,000 ppm (such as between
about 10
ppm and about 5,000 ppm); a silica content of at least about 50 ppm (such as
at least
about 250 ppm, or between about 50 ppm and about 400 ppm); a hardness content
of
at least about about 5 ppm (such as at least about 10 ppm, or between about 5
ppm
and about 225 ppm); or a combination thereof.
[0017] Steps of de-oiling and treating the oily produced water stream may
be carried
out in a water treatment module, to produce a treated water stream that is
maintained
by the fluid handling system at a temperature of at least about 100 C in the
absence of
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CA 3016971 2018-09-07
heating. The treated water stream may for example have: a residual oil content
of less
than about 25 ppm (such as less than about 5 ppm; a silica content of at least
about 50
ppm (such as between about 50 ppm and about 400 ppm); a hardness content of at
least about 5 ppm (such as between about 5 ppm and 225 ppm); or a combination
thereof.
[0018] Make up water may be added to the treated water to produce a steam
generator input fluid stream, and the treated water and the steam generator
input fluid
may be maintained by the fluid handling system at a baseline steam generator
input
temperature of at least about 100 C in the absence of heating. In select
embodiments,
at least about 75% of the steam generator input fluid volume is made up of
fluid from
the oily produced water.
[0019] Steam may be generated from the steam generator input fluid stream
in a
steam generator. In select embodiments, the steam generator may for example
produce
an outlet stream comprising steam of at least about 75% quality. A thermal
recovery
fluid comprising the steam may then be injected into the hydrocarbon
reservoir, and the
injected steam quality may for example be at least about 70%.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] Figure 1 is a schematic illustration of a fluid processing system,
showing
modules or subsystems within the dash-dotted line that together make up an
interconnected and contained fluid handling system operating above ambient
atmospheric pressure.
[0021] Figure 2 is a schematic illustration of a fluid processing system
that includes
an upside down treater (UDT), compact floatation unit (CFU), flash steam
generator
(FSG) and a produced oil upgrading process that involves viscosity reduction
by a mild
thermal cracking process which may involve enhancements or modifications such
as
shearing.
[0022] Figure 3 is a schematic illustration of a modification to the
process of Figure 2
for a thermal hydrocarbon recovery well pad.
[0023] Figure 4 is a schematic illustration of a further modification to
the process of
Figure 2, including a propane diluent emulsion treating system in place of the
upside
down treater.
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CA 3016971 2018-09-07
[0024] Figure 5 is a schematic illustration of a modification to the
process of Figure 4
for a thermal hydrocarbon recovery well pad.
[0025] Figure 6 is a schematic illustration of a modification to the
process of Figure 2
above including a once through steam generator (OTSG) instead of a FSG.
[0026] Figure 7 is a schematic illustration of a modification to the
process of Figure 6
for a thermal hydrocarbon recovery well pad.
[0027] Figure 8 is a schematic illustration of alternative upgrading
processes.
[0028] Figure 9 is a schematic illustration of a further modification to
the process of
Figure 4, including conventional diluent emulsion treating system in place of
the
propane diluent treating.
[0029] Figure 10 is a schematic illustration of a modification to the
process of Figure
9 for a thermal hydrocarbon recovery well pad.
DETAILED DESCRIPTION
[0030] Various aspects of the present disclosure involve integrated and
energetically
efficient methods and systems for processing fluids for use in thermal
hydrocarbon
recovery processes. To achieve energetic efficiencies, these processes are
"integrated"
in the sense that a series of subsystems, assemblies or modules are
implemented in an
interconnected and contained fluid handling system. The containment of the
system
facilitates the operation of the whole process at elevated temperatures, and
at
correspondingly high pressures, above ambient atmospheric pressure. Because
the
subsystems, assemblies, and/or modules are implemented in an interconnected
and
contained fluid handling system, they may be implemented as part of a well-pad
scale
facility which may be modular, portable, and/or upgradable. Additionally or
alternatively,
the subsystems, assemblies, and/or modules may be implemented in a central
processing facility.
[0031] In an initial stage of the process, an oil-water emulsion may be
produced from
a hydrocarbon reservoir undergoing the thermal recovery process, such as a
SAGD
process, cyclic steam simulation (CSS), steam flooding (SF), solvent assisted-
cyclic
steam simulation, toe-to-heel-air-injection (THAI), a solvent-aided process
(SAP), or a
combination thereof (for example occurring at different well pads that feed
into fluid
handling processes and systems described herein). The production fluids may
include a
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CA 3016971 2018-09-07
significant proportion of connate water produced from the reservoir. The
emulsion 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 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] The produced oil:water ratio of the emulsion may for example be from
about
20:80 to about 90:10, or any ratio between these values, and will of course
typically
fluctuate over time during production. In a SAGD process, this ratio may for
example be
from about 20:80 to about 35:65. In a 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
emulsions for example being characterized by one or more parameters that may
include
50-900 mg/L total suspended solids (TSS), 50-400 mg/L silica, 5-75 mg/L or
alternatively 5-225 mg/L hardness, 30-700 mg/L soluble organics measured as
total
organic carbon (TOC), or a combination thereof.
[0033] The produced emulsion may be separated into a produced oil stream and
an
oily produced water stream in an emulsion treating module. This emulsion
treating
module may be operated so that the oily produced water stream is maintained by
the
fluid handling system at a baseline temperature, for example of at least 100
C, 125 C,
150 C, 160 C, 170 C, 175 C, 180 C, 185 C, 190 C, 195 C, 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 fluid handling system at a
temperature of at least about 190 C to about 200 C and/or a pressure of
between about
1 MPa and about 3.1 MPa. A heater utilized for heating may be 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, or
any other
suitable heater as would be understood by a person of skill in the art. In the
absence of
this optional heating, the fluid handling system is constructed as an
interconnected and
contained fluid handling network, and operated so that it maintains the
processed fluids
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close to or above this baseline temperature. Enthalpy maintenance subsystems
of the
fluid handling system may for example be adapted so that the temperatures
and/or
pressures maintained in the emulsion treating module 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 subsystem may for example include insulation and other fluid
handling
adaptations that maintain the temperature and/or pressure of fluids within the
fluid
handling system.
[0034] Exemplary emulsion treating modules may for example involve one or
more
of a membrane separation process, an upside down treater (UDT) process, a hot
hydrocyclone process or a propane or other diluent or solvent treating system,
for
example using a natural gas condensate, propane, butane, pentane or other
alkanes or
alkane mixtures.
[0035] Oil-water separation is advancing with membranes that, for example,
allow oil
to pass through but not water. An alternative membrane separation system may
consist
of a pressurized filter system with membrane cartridges/units in place of
traditional
filters. A suitable membrane may be utilized to aid in oil-water separation,
thus reducing
the need for traditional produced emulsion treating chemicals and/or diluents.
[0036] In an aspect of an upside down treater process, the produced
emulsion may
be heated to a relatively high temperature range, for example of at least
about 150 C or
180 C, from about 150 C to 250 C, or from about 180 C to 230 C, to provide a
lower
viscosity and wider density difference between oil and water; the hot emulsion
may
separate with the oil portion being more dense than the water portion, hence
the term
'upside down'. The emulsion separation may reduce or eliminate the need for
diluent
and may reduce or eliminate the need for treatment chemicals compared to a
conventional SAGD operation, and may produce semi-dry oil and relatively clean
produced water streams. The semi-dry oil may then be flashed in a flash
treater to
remove the remaining water to below 0.5% basic sediment and water (BS&W) while
remaining in, for example, the 180 C to 230 C temperature range. Concurrently
the
produced water may optionally also remain at the same high temperature range
with oil
in water contents below about 2,000 ppm.
CA 3016971 2018-09-07
[0037] Similarly, in an aspect of a hot hydrocyclone process, the emulsion
may be
heated to a relatively high temperature range of about 180 C to 230 C to
provide a
lower viscosity and wider density difference between oil and water, and this
may allow
for hot emulsion separation with the oil portion being heavier than the water
portion.
Cyclones, hydrocyclones or oleocyclones may replace conventional SAGD process
facility vessels and may involve single or multiple stage separation. The
cyclones make
use of the angular velocity of the fluids to impart higher acceleration forces
and may
separate oil and water more efficiently than traditional gravity separation
equipment.
Emulsion may be degassed, prior to or in the absence of heating, and then may
be
pumped up to a higher pressure such as 1,500 kPag to 2,500 kPag to prevent
flashing
in the cyclone. The emulsion may then enter the cyclone unit where the
difference in
density between oil and 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
required product qualities for further processing, transportation, or
disposal.
Additionally, pumps may be required to overcome the pressure drop require for
each
cyclone stage. The emulsion separation may require less or fully eliminate the
need for
traditional diluent treating and may require less or fully eliminate the need
for treatment
chemicals to produce semi-dry oil and relatively clean produced water streams.
The
semi-dry oil may then be flashed in a flash treater to remove the remaining
water to
below 0.5% BS&W and may remain at an elevated temperature, for example of at
least
about 180 C, or about 180 C to 230 C. Concurrently the produced water may also
optionally remain at about 180 C to 230 C with oil in water contents below
about 2,000
ppm.
[0038] The emulsion treating process may be carried out so as to separate a
high
proportion of the oil, leaving the oily produced water 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
separated
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
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specifications. The oily produced water may be maintained at elevated
temperatures
and pressures within the contained fluid handling system. Dissolved and
entrained
materials in the oily produced water 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 50 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 for each foregoing parameter a
select
proportion of the relevant chemical species segregates into the oily produced
water. For
example, at least 70%, 75%, 80%, 85%, 90%, 95% or 98% of the TSS, silica,
hardness,
TOC, or a combination thereof, present in the produced emulsion may be
segregated
into the oily produced water. The treated water may comprise at least 70%,
75%, 80%,
85%, 90%, 95% or 98% of the TSS, silica, hardness, TOC, or a combination
thereof,
segregated into the oily produced water.
[0039] The produced oil stream may be discharged from the fluid handling
system,
for example for upgrading. Processes of upgrading may take advantage of
residual heat
present in the discharged produced oil stream by virtue of the elevated
temperatures
and pressures used to treat the produced emulsion. Upgrading the produced oil
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 patent documents
CA2611251, CA2617985, CA2858705, CA2858877). 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
(TAN), sulfur content, or a combination thereof, and partial upgrading may be
utilized to
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help meet oil transportation (e.g., pipeline, railway) specifications. The
produced oil
stream may be further heated to above about 350 C and the oil may be partially
upgraded, for instance, by converting longer heavy oil chains into smaller
chains, which
lowers 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 solutions 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] The oily produced water may be further de-oiled and/or treated in a
water
treatment process to reduce oil and components with the potential to foul
(scale) a
downstream steam generator. Conventional systems de-oil and treat water below
100 C because of the use of equipment such as tanks, which must occur below
the
normal boiling point of the contents therein to ensure containment.
Conventional
systems also have temperature limitations of processes, for example, hardness
removal
resins degrade at higher temperatures. Some conventional systems use
evaporators,
which necessarily involve energetically expensive phase changes.
[0041] Treatment of the oily produced water may for example be carried out so
as to
produce a treated water stream having: 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.. õ In select embodiments, the
treated water
stream may for example have residual TSS, silica, hardness, and TOC 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 TSS, silica, hardness, and/or TOC
values of the oily produced water stream.
13
CA 3016971 2018-09-07
[0042] Oily produced water treatment according to an alternative embodiment
may
for example be carried out so as to produce a treated water stream having an
oil
concentration of less than 1 ppm (alternatively up to 100 ppm), a hardness of
less than
0.1 ppm (where hardness refers to free calcium, magnesium, lithium and/or
strontium
ions; and where the oily produced water may be characterized by a hardness of
up to
25 ppm), and a silica concentration of less than 50 ppm (where oily produced
water may
be characterized by a silica concentration of up to 350 ppm). In alternative
embodiments, hardness may for example be maintained at <0.5 ppm.
[0043] The process of de-oiling and treating the oily produced water stream
may be
performed to recover valuable oil and reduce scale formation (fouling) during
subsequent steam generation. Produced water may contain between 200 and 10,000
ppm oil, between 5 and 225 ppm hardness, between 100 and 350 ppm silica,
between
25 and 75 ppm dissolved organics, or a combination thereof. While some steam
generation processes may not require produced water de-oiling or treatment,
such as
Direct Steam Generation (DSG), Flash Steam Generation (FSG) and/or a Fluidized
Bed
Boiler (FBB) (see CA2947355), other steam generation processes may require at
least
some produced water de-oiling and treatment such as a Once Through Steam
Generator (OTSG).
[0044] De-oiling the produced water as much as possible, for example, to
below 50
ppm oil, may be desirable because the oil is a valuable product to recover.
The use of
floatation processes, units, and/or systems for oil separation is advantageous
for high
temperature, pressurized produced water treatment applications because
floatation is
typically performed in vessels that may be designed for most, if not any,
operating
conditions. Examples of floatation technologies include a Compact Floatation
Unit
(CFU, 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)), which is a multistage,
typically vertical, vessel with swirling/cyclonic separation enhancement;
traditional
multistage horizontal floatation units; or single stage floatation units.
Additional oil
separation processes may include hydrocyclones, filter presses, traditional
filters or
membrane filters (see for example oil removal filtration processes as
described in US
Patent Nos: US6180010, U55437793, U55698139, U55837146, U55961823 and
14
CA 3016971 2018-09-07
US7264722; and, hydrocyclones as for example described in US Patent Nos.
US5017288, US5071557 and US5667686).
[0045] Oily produced water treatment processes may involve the reduction of
steam
generator scaling components within the oily produced water stream and may
occur
before, during or after the de-oiling process. The oily produced water may be
processed to generate a treated water in a water treating module. The desired
treated
water quality depends on the steam generation process to be utilized and oily
produced
water treatment processes prior to steam generation may include ion exchange
to
reduce hardness, chemical addition to reduce reactive silica (for example, by
adding
magnesium oxide or a silica inhibitor), chemical or electrical reduction of
organics,
hardness and/or silica, or a combination thereof. Oily produced water
treatment
processes may involve an electro-flocculation (EF) or electro-coagulation (EC)
process
of imparting voltage and current through submerged metal plates, commonly
formed of
iron, to generate a metal ion rich solution. Hydroxide or other flocs may be
formed from
the solution, at an appropriate pH. These flocs serve to remove the
contaminants in the
water by various mechanisms, such as absorption and coagulation. Oily produced
water
treatment processes may involve a cationic resin to attract free hardness
ions. The resin
may then be regenerated, for example when exhausted, with either brine or acid
and
caustic solutions. Oily produced water treatment processes may involve
selective
membranes in reverse osmosis or other flow arrangements. These or other oily
produced water treatment processes may be utilized to generate a treated
water.
[0046] In select embodiments, make up water may be added to the treated
water to
produce a steam generator input fluid stream. The make up water may be
combined
with the treated water in equipment such as piping, a tank, a vessel, or a
combination
thereof. Make up water may be processed and/or handled, for example, 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, prior to combining the make up water with the treated
water. 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
CA 3016971 2018-09-07
water may be facilitated via a glycol system, cooler, or any other suitable
heat exchange
process as would be understood by a person of skill in the art.
[0047] The treated water and the steam generator input fluid stream may for
example be maintained by the fluid handling system at a baseline steam
generator input
temperature and/or pressure. For example, the treated water stream and the
steam
generator input fluid stream may be maintained at a temperature of at least
100 C,
125 C, 150 C, 160 C, 170 C or 175 C in the absence of heating and/or at a
pressure of
between about 1 MPa and about 3.1 MPa. Optionally, the steam generator input
fluid
stream may be heated above the baseline steam generator input temperature; in
the
absence of this optional heating, the fluid handling 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. By reducing the
usage
of tanks, reducing the number of equipment steps needed, and ensuring
appropriate
insulation, the produced fluids may be maintained at a relatively high
temperature,
which may improve system efficiency compared to a conventional SAGD facility.
The
enthalpy maintenance subsystems of the fluid handling 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 steam generator input fluid stream, temperatures and/or
pressures are
maintained within a particular degree of departure from the temperatures
and/or
pressures of the water treatment module, for example within a variation of
20%, 15%,
10% or 5%.
[0048] In select embodiments, produced fluid recycling efficiencies are
provided by
the contained fluid handling system, so that the ratio of oily produced water
volume to
steam generator input fluid volume 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 volume as possible moves forward for use as
the
steam generator input fluid stream. Similarly, the contained fluid handling
system may
be adapted to maintain a relatively high ratio of treated water volume to make
up water
volume, for example of at least 7:3, 8:2 or 9:1, representing for example at
least 70% of
the treated water volume being utilized for steam generation along with 30%
make up
water.
16
CA 3016971 2018-09-07
[0049] The enthalpy maintenance subsystems 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 fluid
handling
system, for example within 50 C, 40 C, 30 C or 20 C.
[0050] The steam generator input fluid stream may be converted into steam
in a
steam generator, such as a flash steam generator, fluidized bed steam
generator, direct
steam generator, OTSG, or a steam generator that further comprises a steam
separator. In embodiments wherein the steam generator further comprises a
steam
separator, the fluid handling system may further comprise a recirculation line
that is
operable to recirculate non-vapourized outlet fluids from the steam separator
back into
the steam generator input fluid stream as describe in Canadian patent
application
number 2,987,237. The steam generator (optionally comprising the steam
separator)
may be adapted to produce an outlet stream comprising steam of a select
quality (the
proportion of gaseous water in the total fluids produced by the steam
generator), for
example greater than 20%, on the order of at least 70%, 75%, 80%, 85%, 90% or
95%
steam quality. This steam may then be delivered by the fluid handling 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 65%, 70%, 75%, 80%, 85% or 90%. In this
context, steam 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.
[0051] Figure 1 is a schematic illustration of a fluid processing system,
showing
modules or subsystems within the dash-dotted line that together make up an
interconnected and contained fluid handling system operating above ambient
atmospheric pressure. An exemplary embodiment is illustrated in Figure 2,
which
includes an upside down treater (UDT), compact floatation unit (CFU), flash
steam
generator (FSG, illustrated as the Fired Heater and Flash Vessel) and a
produced oil
upgrading process (from Charge Pump to Hydro-polisher) that involves viscosity
17
CA 3016971 2018-09-07
reduction by thermal cracking and cavitation induced by shearing. In select
implementations of such an embodiment, demulsifier and/or reverse emulsion
breaker
may for example be added upstream of the inlet degasser and UDT (and
optionally
added to slop tanks). In addition, a clarifier may be added to the inlet or
oily produced
water outlet of the UDT. A pH adjustment may take place, for example at the
inlet of the
BF\N surge vessel. For corrosion control, an amine inlet may for example be
included in
the steam line out of the FSG. 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. In select implementations of the illustrated processes of
Figure 2,
operating temperatures in the interconnected and contained fluid handling
system may
be in the range of about 180 C-220 C, throughout the train of treatment steps,
with that
temperature maintained through the deoiling, water treatment and boiler feed
water
processes. In select embodiments, the steam generator input fluid stream may
be
characterized as having about 1-5 ppm oil and grease, about 200-250 ppm
silica, and
about 15-20 ppm hardness.
[0052] In alternative embodiments of the illustrated process, the emulsion
may for
example be heated to a temperature range of about 180 C to 230 C which
provides a
lower viscosity and wider density difference between oil and water than at
lower
temperatures, and which may allow this relatively hot emulsion to separate
with the oil
portion being heavier than the water portion, hence explaining the term
'upside down,'
as discussed above. The emulsion separation may require reduced or no diluent
(for
example, a natural gas condensate as is utilized in some conventional SAGD
operations) and reduced or no treatment chemicals to produce semi-dry oil and
clean
produced water streams (for example the process may be carried out without a
demulsifier). The semi-dry oil may then be flashed in, for example, a flash
treater to
remove the remaining water to below 0.5% BS&W. Alternatively, other oil
polishing
equipment may be utilized, for example a cyclone or secondary treater.
[0053] The oil may remain at about 180 C to 230 C, and may be fed directly
into the
partial upgrading process where it may be further heated to above 350 C and
sheared
to convert long heavy oil chains into smaller chains, which may lower the
viscosity to
yield a partially upgraded oil. The oil may then be fractionated and hydro-
polished to
reduce olefin content to typical pipeline specifications of <1%. Concurrently,
the hot,
18
CA 3016971 2018-09-07
pressurized oily produced water that was separated from the emulsion may be de-
oiled
through a CFU and then may be dosed with chemicals, such as caustic (NaOH) to
increase the pH, chelants to reduce free scaling ions, sulfite to reduce free
oxygen, or a
combination thereof, to produce treated water for steam generation. A surge
vessel
may be required to even out steam generator input fluid (i.e. BFW) stream flow
into the
steam generation system. The BFW (which may include both treated 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 steam fraction at
about 300 C
to 400 C, and flashed in a flash vessel to create a steam fraction of 20 to
40% steam
quality. This dry steam may be injected into the reservoir for thermal
hydrocarbon
recovery processes, while the remaining liquid fraction (known as blowdown)
may be re-
pressurized, filtered, and recombined with the BFW 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, or recycled back into the BWF.
[0054] In an alternative embodiment, a solvent (for example, propane or
butane)
may be injected into the steam generation 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 interconnected and contained fluid
handling
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). Alternatively, for example, one or
more natural
gas liquids (NGLs)-rich vapour streams from the treating vessels may be cooled
to
condense the gaseous NGLs into a liquid phase (for example from the Inlet
Degasser,
FWKO, Treater, Upside Down Treater, and/or Flash Treater), so that a three
phase
separator (3 Phase Sep) is where the solvent is ultimately recovered from the
water/NGL/vapour mixture. The NGL phase may be, for example, propane rich and
may
be re-used as a solvent. Cooling prior to separation may occur either through
aerial
coolers or a chilling system. In alternative embodiments, the solvent 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
19
CA 3016971 2018-09-07
deployed as a mobilizing fluid, comprising for example one or more C3 through
C10
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, for example n-propane or n-butane, or a mixture such as n-
butane +
iso-butane.
[0055] Shown in Figures 1 and 2 are the integration of several different
major facility
component areas, representing modules, subsystems or assemblies within the
overall
fluid handling process. The modules, subsystems, and/or assemblies may be
implemented as part of a well-pad scale facility which may be modular,
portable, and/or
upgradable. Additionally or alternatively, the subsystems, assemblies, and/or
modules
may be implemented in a central processing facility. Figure 1 outlines in a
dash-dotted
line an exemplary collection of subsystems or modules that together make up an
interconnected and contained fluid handling system operating above ambient
atmospheric pressure, taking produced fluids from the production wellhead,
treating and
recirculating those fluids, to provide the injection fluids at the injector
wellhead. As
shown in Figure 2, the high temperature produced oil stream produced in the
emulsion
treating module (including an emulsion heater, upside down treater, and flash
treater)
with reduced or no diluent treating may be coupled to a partial upgrading
module,
subsystem or assembly (including a crude heater, shear module, post-reaction
fractionation module, and hydro-polishing module), where less heat input is
required
compared to conventional SAGD processing facilities and upfront fractionation
may not
be required. Additionally, the elevated temperature, pressurized water
treatment
module (including a compact floatation unit (CFU)) allows for a reduced aerial
footprint
compared to traditional systems; by maintaining the treated water at an
elevated
temperature, the treated water may be delivered to the steam generation
subsystem or
module (including a flash steam generator (FSG)) with less heat exchange
required
than in conventional SAGD facilities and a higher temperature BFW may increase
the
efficiency of the steam generation system.
[0056] Figure 3 is a schematic illustration of a modification to the
process of Figure
2, for conventional thermal recovery well pad use. While the process is
generally the
same, allowances may be provided for operational upset conditions (e.g.,
during a
scenario in which one or more pieces of equipment must be shut down for
CA 3016971 2018-09-07
troubleshooting or maintenance) to send slop to a central processing plant
instead of a
separate slop system. There may also be allowances for external steam
injection from
another source such as a central plant steam header.
[0057] The exemplary embodiment of Figure 4 includes a propane (C3)
diluent,
which dissolves in the oil phase in the produced emulsion to promote
floatation of the oil
in a process that typically operates at temperatures of about 120 C to 150 C.
The
propane diluent emulsion treating system may alternatively operate at lower
temperatures, for example of 100 C to 150 C, and may make use of chemical
injection
to aid in oil-water separation, such as a dennulsifier and/or reverse breaker.
In some
embodiments, as illustrated, the propane diluent treating system may include a
free
water knockout ("FWKO") and Treaters for water removal. The FWKO units and
treaters
may for example be operated at about 125 C to 145 C and about 900-1,500 kPag.
Optionally a flash vessel may be provided to reduce pressure to 100 to 800
kPag to
flash off the propane which may then be sent to a vapour cooling system for
capture
and reuse. The process as illustrated also includes a CFU, FSG and a produced
oil
upgrading process that involves viscosity reduction by thermal cracking and
cavitation
induced by shearing. In such an embodiment, demulsifier and/or reverse
emulsion
breaker may for example be added upstream of the inlet degasser and treaters.
In
addition, a clarifier may be added to an oily water outlet from the FWKO,
treaters, or
both. A pH adjustment may take place, for example at the inlet of the BFW
surge
vessel, and an amine inlet may for example be included in the steam line out
of the
FSG. In select implementations of the illustrated processes of Figure 4,
operating
temperatures in the interconnected and contained fluid handling system may be
in the
range of about 100 C-150 C, throughout the train of treatment steps, with that
temperature maintained through the deoiling, water treatment and boiler feed
water
processes. In select embodiments, the steam generator input fluid stream may
be
characterized as having about 1-5 ppm oil and grease, about 200-250 ppm
silica, and
about 15-20 ppm hardness.
[0058] Figure 5 is a schematic illustration of a modification to the
process of Figure
4, for conventional thermal hydrocarbon recovery well pad use. While the
process is
generally the same, there may be allowances for upset conditions to send slop
to the
21
CA 3016971 2018-09-07
central processing plant instead of a slop system. There may also be
allowances for
external steam injection from another source such as the central plant steam
header.
[0059] Figure 6 is a schematic illustration of a modification to the
process of Figure
2, showing an alternative oily produced water treatment process and an
alternative
steam generation process (OTSG instead of FSG). An electro-flocculation or
electro-
coagulation unit may be added to the water treatment module, with pH
adjustment to
create iron flocks to reduce organics, silica, hardness and oil in the oily
produced water
stream; the flocks may then be removed in the CFU along with additional oil
present in
the oily produced water stream. The steam generator may be a traditional once
through
steam generator with BFW quality specifications such as up to about 350 ppm
silica, up
to about 15 ppm hardness, up to about 2 ppm oil, or a combination thereof. The
exemplary embodiment of Figure 6 includes an UDT, CFU, OTSG and a produced oil
upgrading process that involves viscosity reduction by thermal cracking and
cavitation
induced by shearing. In select implementations of such an embodiment,
demulsifier
and/or reverse emulsion breaker may for example be added upstream of the inlet
degasser and UDT (and optionally to slop tanks). A clarifier may be added to
the inlet of
the UDT or oily produced water downstream of the UDT, or a combination
thereof. A pH
adjustment may take place, for example at the inlet of the BFW surge vessel,
and an
amine inlet may for example be included in the steam line out of the OTSG. In
select
implementations of the illustrated processes of Figure 6, operating
temperatures in the
interconnected and contained fluid handling system may be in the range of
about
180 C-220 C, throughout the train of treatment steps, with that temperature
maintained
through the deoiling, water treatment and boiler feed water processes. In
select
embodiments, the steam generator input fluid stream may be characterized as
having
about 0-2 ppm oil and grease, about 15-50 ppm silica, and about 1-2 ppm
hardness.
[0060] Figure 7 is a schematic illustration of a modification to the
process of Figure
6, for conventional thermal recovery well pad use. While the process is
generally the
same, there may be allowances for upset conditions to send slop to the central
processing plant instead of a slop system. There may also be allowances for
external
steam injection from another source such as the central plant steam header.
[0061] In select implementations of the illustrated embodiments, emulsion
produced
from the reservoir may for example range in temperature from about 160 C to
230 C,
22
CA 3016971 2018-09-07
with a pressure as high as 2,700 kPag (approximately steam saturation pressure
at
230 C). In some cases, the UDT may for example operate at temperatures of
about
170 C to 220 C, with a pressure as high at 2,300 kPag (approximately steam
saturation
pressure at 220 C).
[0062] A wide variety of alternative oil upgrading processes may be
implemented in
alternative embodiments. Figure 8 illustrates exemplary embodiments of an oil
upgrading process, that may for example include a partial upgrading reaction
module
"P" and a post-reaction fractionation module ("F"), to separate hydrocarbon
fractions. As
illustrated, the produced oil stream 1 enters the crude heater. The output
stream 2 from
the crude heater enters the partial upgrading reaction module. The output
stream 3 from
the partial upgrading reaction module enters the fractionation module. The
fractionation
module segregates a heavy fraction 5 from a light fraction 4, with light
fraction 4
proceeding to hydro-polishing to produce output stream 7. Both fractions 5 and
7 are
returned for re-blending as combined output stream 6 back into the product
sales oil. In
select embodiments, the partial upgrading reaction module may for example
include
technologies such as: conventional thermal cracking/visbreaking, Fractal's
JetShear
technology, FluidOil's HTLNHTL technology, hydrogen-donor assisted thermal
cracking, thermal decarboxylation, catalyst-assisted thermal processes,
hydroprocessing (for example, hydrocracking, slurry hydrocracking, molten-
sodium
assisted hydrocracking, hydrotreating, or a combination thereof). In select
embodiments, particularly the shearing example set out above, process
conditions for
fluid flow in the upgrading module may for example be as set out in the
following Table.
Stream Temperature (deg. C) Pressure (psig)
1 -100 2000 - 4000
2 390 - 450 2000 - 3750
3 390 - 425 75 - 250
4 50 - 200 300 - 500
200 - 400 100 - 250
6 20 - 80 20 - 100
7 40 - 350 20 - 100
23
CA 3016971 2018-09-07
[0063]
Figure 9 is a schematic illustration of a modification to the process of
Figure
4, showing conventional diluent based emulsion treating in place of the
solvent (e.g.,
propane) emulsion treating described above. An additional diluent recovery or
fractionation step may be added prior to the partial upgrading solution, with
that
recovered diluent being optionally reused in the emulsion treating process.
Additional
diluent may also be required for treating. In select implementations of the
illustrated
processes of Figure 9, operating temperatures in the interconnected and
contained fluid
handling system may be in the range of about 120 C-150 C, throughout the train
of
treatment steps, with that temperature maintained through the deoiling, water
treatment
and boiler feed water processes. In select embodiments, the steam generator
input
fluid stream may be characterized as having about 1-5 ppm oil and grease,
about 150-
250 ppm silica, and about 10-20 ppm hardness.
[0064]
Figure 10 is a schematic illustration of a modification to the process of
Figure
9, for conventional thermal recovery well pad use. While the process is
generally the
same, there may be allowances for upset conditions to send slop to the central
processing plant instead of a slop system. There may also be allowances for
external
steam injection from another source such as the central plant steam header.
[0065]
Although various embodiments of particular innovations are disclosed herein,
many adaptations and modifications may be made within the scope of the
invention in
accordance with the common general knowledge of those skilled in this art.
Such
modifications include the substitution of known equivalents for any aspect of
the
invention in order to achieve the same result in substantially the same way.
Numeric
ranges are inclusive of the numbers defining the range. The word "comprising"
is used
herein as an open-ended term, substantially equivalent to the phrase
"including, but not
limited to", and the word "comprises" has a corresponding meaning. As used
herein, the
singular forms "a", "an" and "the" include plural referents unless the context
clearly
dictates otherwise. Thus, for example, reference to "a thing" includes more
than one
such thing. References herein to "modules" or "subsystems" or an "assembly"
generally
connote an interoperating component of a larger system, with a meaning
informed by
the broader context of the description, where that component is itself made up
of
interoperating parts or processes (and as such these words may be used
24
CA 3016971 2018-09-07
interchangeably). Citation of references herein is not an admission that such
references
are prior art to the present invention. Any priority document(s) and all
publications,
including but not limited to patents and patent applications, cited in this
specification are
incorporated herein by reference as if each individual publication were
specifically and
individually indicated to be incorporated by reference herein and as though
fully set forth
herein. The invention includes all embodiments and variations substantially as
hereinbefore described and with reference to the examples and drawings.
CA 3016971 2018-09-07
