Note: Descriptions are shown in the official language in which they were submitted.
A8141946CA
METHODS AND SYSTEMS FOR TWO-STAGE STEAM GENERATION
TECHNICAL FIELD
[0001] The present disclosure generally relates to methods and
systems for
generating steam for in-situ hydrocarbon recovery processes. In particular,
the present
disclosure relates to methods and systems that are suitable for generating
steam from
produced water while attenuating steam generator fouling.
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 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 conventional produced water recycling processes, a produced
emulsion
is recovered from a hydrocarbon reservoir and subjected to coarse oil-water
separation to
provide a produced water stream. The produced water stream typically contains
a variety
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of undesirable dissolved and/or entrained components such as calcium,
magnesium,
carbonates, silica, and/or silicates. These components (and others) are
problematic for
steam generation in that they tend to form scale deposits on surfaces within
the steam
generator (i.e. steam generator fouling). Scale deposits are known to reduce
the heat
transfer coefficient and this insulating effect reduces operational efficiency
and requires a
higher heated surface temperature to effect available heat transfer potential.
Scale deposits
are also associated with increased maintenance requirements, more frequent
generator
shut downs, and/or more frequent boiler tube failures. Accordingly,
conventional produced
water recycling processes typically employ water treatment steps such as lime
softening
and/or ion exchange which are designed to decrease the concentration of
undesirable
dissolved/entrained components to levels that meet or exceed industry
standards for steam
generation feedwaters. Water treatment steps typically require specialized
equipment,
increase energy demand, consume materials, create waste, and increase system
complexity. Accordingly, methods for water heating, particularly steam
generation, that
reduce or eliminate the requirement for water treatment after emulsion
separation are
desirable ¨ especially when such methods attenuate fouling caused by scale
deposition.
[0005] Steam generator fouling is associated with nucleate boiling
which is one of
a series of phenomena that may occur as feedwater is converted to steam.
Briefly stated,
boiling in a steam generator is induced by heat transfer through a super-
heated surface,
and the mechanism of heat transfer to the feedwater may change as a function
of the
magnitude of the heat flux and/or the difference in temperature between the
super-heated
surface and the feedwater, the local fluid velocity, the thernno-physical
properties of the
fluid, and/or steam quality. In general, heat transfer in a steam generator
proceeds from a
forced liquid convective heat transfer regime, to a subcooled and saturated
nucleate boiling
heat transfer regime, to a forced convection evaporative heat transfer regime,
and finally to
a forced vapor convective heat transfer regime. In the liquid convective heat
transfer
regime, the feedwater is heated such that the local fluid temperature
approaches (but does
not reach) the local saturation temperature. As such, little if any feedwater
boiling occurs in
the liquid convective heat transfer regime, and the liquid convective heat
transfer regime is
generally not associated with generator fouling. In the nucleate boiling heat
transfer regime,
heat flux through the super heated surface induces feedwater boiling at
discrete locations
on the surface (e.g. at surface micro-cavities or other small-scale surface
deformations).
These phenomena are associated with scale deposition and steam generator
fouling, as
the liquid-vapor transition occurs on the surface of the boiler tube. In the
forced convection
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evaporative heat transfer regime, the majority of the liquid-vapor transition
occurs away
from the surface, as the surface is substantially covered by a non-boiling
layer (i.e. a liquid
or vapor film). Like the liquid convective heat transfer regime, the forced
convection
evaporative heat transfer regime is associated with a lower rate of fouling.
Nucleate boiling
has accordingly long been recognized not as an avoidable problem, but as an
inherent
consequence of the thermodynamic imperatives of steam generation.
[0006] Steam generator fouling is also associated with steam
generation under
dryout conditions. Briefly stated, dryout conditions are thought to occur when
the liquid
inventory of a stream is not sufficient to maintain wetted conditions along
the heat-transfer
surface. Dryout conditions are generally associated with high steam qualities
and high-
velocity flowrates. Under dryout conditions, the liquid inventory may be
carried in the bulk
flow as a mist and any liquid droplets that do manage to contact the wall are
likely to
evaporate on contact thereby depositing previously dissolved materials onto
the heat-
transfer surface.
SUMMARY
[0007] The present disclosure recognizes that there is an unmet need
for new,
alternate, and/or improved methods and systems for generating steam from
produced
water, especially for produced water that is de-oiled but otherwise untreated
(or minimally
treated). The methods and systems disclosed herein utilize a two-stage steam
generation
strategy that attenuates steam generator fouling by mitigating (i.e. reducing
or eliminating)
nucleate boiling on super heated surfaces within the steam generator.
[0008] In the first stage, a feedwater stream is pressurized and
heated to a first
pressure/temperature condition. These first pressure and temperature
conditions may
optionally be selected so that the feedwater is sufficiently subcooled to
ensure that the
localized heat flux is not sufficient to induce nucleate boiling (subcool is
the difference
between the saturation temperature (boiling point) of the feedwater at a given
pressure and
the lower actual temperature of the feedwater at the given pressure). Under
such a
condition, heat transfer occurs by forced liquid convection. The second stage
¨ and the
transition from the first stage to the second stage ¨ is configured to ensure
a near
instantaneous transition to a condition above a threshold steam quality. As
set out in detail
below, staying above a threshold steam quality prioritizes forced convective
evaporation
such that nucleate boiling is not a dominant heat-transfer mechanism.
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[0009] The present disclosure is based on state-of-the-art modelling
which, after
extensive research and development, elucidate two unique approaches to
generating
steam while mitigating nucleate boiling. In one approach, as the feedwater
stream
approaches the saturated nucleate boiling regime, an auxiliary-steam stream is
utilized to
boost the steam quality above the threshold steam quality and into the
convective
evaporative heat transfer regime. In the other approach, an atypical flow-path
is coupled
with a pressure-reducing element to the same effect. Importantly, as set out
in detail below,
incorporating a pressure-reducing element into a conventional flow path is
unlikely to satisfy
the tolerances associated with steam generation for hydrocarbon recovery. The
combination of a pressure-reducing element and a particular type of flow path
is required
in the absence of an auxiliary-steam stream.
[0010] The two approaches can also be combined and, whether taken
alone or
together, they allow for efficient steam generation while attenuating steam
generator
fouling. As such, the methods and systems of the present disclosure may be
suitable for
generating steam from produced water that is de-oiled but otherwise untreated
or minimally
treated. Such methods and systems could be used to extend the operating time
between
cleanings for existing operations with more fully treated water.
Approach 1: Utilizing an auxiliary-vapour stream
[0011] One general aspect includes a method of generating steam for
use in a
hydrocarbon production process, the method including: pressurizing a feedwater
stream to
a first feedwater pressure condition and heating the feedwater stream to a
first feedwater
temperature condition, to provide a heated feedwater stream. The method of
generating
steam also includes combining the heated feedwater stream with an auxiliary
vapour
stream to form a vapour-enhanced stream having a controlled vapour-enhanced
steam
quality at a second vapour-enhanced temperature condition and a second vapour-
enhanced pressure condition. The method of generating steam also includes
heating the
vapour-enhanced stream in a steam generator to increase the steam quality
thereof to
provide a heated vapour-enhanced steam stream, where the controlled vapour-
enhanced
steam quality at the second temperature condition and the second pressure
condition is
maintained so as to mitigate nucleate boiling on a heated steam generator
surface within
the steam generator during the heating of the vapour-enhanced stream. The
method of
generating steam also includes injecting at least a portion of the heated
vapour-enhanced
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steam stream into a hydrocarbon-containing reservoir as an injected steam at a
controlled
injected steam quality to facilitate the hydrocarbon production process.
[0012] One general aspect includes a system for generating steam for
hydrocarbon
production, the system including: a pressurizing element that is configured to
pressurize a
feedwater stream to a first feedwater pressure condition, to provide a
pressurized feedwater
stream. The system also includes a convective-heating section configured to
heat the
pressurized feedwater stream to a first feedwater temperature condition, to
provide a
heated feedwater stream. The system also includes a stream connector that is
configured
to combine the heated feedwater stream with an auxiliary vapour stream to form
a vapour-
enhanced stream having a controlled vapour-enhanced steam quality at a second
vapour-
enhanced temperature condition and a second vapour-enhanced pressure
condition. The
system also includes a radiant-heating section configured to heat the vapour-
enhanced
stream in a steam generator to increase the steam quality thereof to provide a
heated
vapour-enhanced steam stream, where the controlled vapour-enhanced steam
quality at
the second temperature condition and the second pressure condition is
maintained so as
to mitigate nucleate boiling on a heated steam generator surface within the
steam generator
during the heating of the vapour-enhanced stream. The system also includes a
steam
injection section configured to inject at least a portion of the heated vapour-
enhanced steam
stream into a hydrocarbon-containing reservoir as an injected steam at a
controlled injected
steam quality to facilitate the hydrocarbon production process.
[0013] Implementations may include one or more of the following
features. The
method and/or system where the auxiliary vapour stream includes an auxiliary
steam. The
method and/or system where the auxiliary steam has a steam quality of greater
than about
90%. The method where the auxiliary steam has a temperature of between about
200 C
and 350 C, or between about 212 C and about 311 C. The method and/or system
where
the auxiliary steam has an auxiliary steam pressure of between about 2 MPa and
about 10
MPa. The method and/or system where the auxiliary steam includes steam
generated in a
separate boiler from a treated water stream. The method and/or system where
the auxiliary
vapour stream includes one or more of a fuel gas, a produced gas, an inert
gas, or an
oxygen-free gas mixture. The method and/or system where the first feedwater
pressure
condition is between about 12 MPa and about 15 MPa, or at least about 12,500
kPa, or at
least about 14,500 kPa. The method and/or system where the second vapour-
enhanced
pressure condition is at least about 3,500 kPa or at least about 5,000 kPa, or
at least about
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9,500 kPa, or between about 3 MPa and about 12 MPa. The method and/or system
where
the second vapour-enhanced temperature condition is between about 200 C and
about
350 C, or between about 234 C and about 325 C. The method and/or system where
heating the vapour-enhanced steam stream includes providing a peak heat flux
of between
about 150 kW/m2 and about 300 kW/m2 and/or providing an average heat flux of
between
about 50 kW/m2 and about 160 kW/m2 (on an inside area basis). The method
and/or system
where heating the feedwater stream to the first feedwater temperature
condition includes
heating to a controlled subcooled feedwater temperature so as to mitigate
nucleate boiling
at the first feedwater pressure condition. The method and/or system where the
controlled
subcooled feedwater temperature is at least about 3 C, 10 C, 20 C, 22 C, 30 C
or 40 C
subcooled. The method and/or system where the controlled subcooled feedwater
temperature is subcooled by a subcool, AT, that satisfies the following
condition:
P =
0 0239
5 ( 2.83
AT > _______________________________
0.8 0.4 k 9 0.00176 * P1.156)
0.023R, Pr 7
wherein:
q is the local heat flux expressed in W/m2,
Re is the Reynolds number,
Pr is the Prandtl number,
k is the fluid thermal conductivity expressed in W/m/ C,
De is the hydraulic diameter, and
P is the system pressure expressed in Pa.
[0014] The
method and/or system may also include heating the feedwater stream
to the first feedwater temperature condition includes maintaining a peak
feedwater heat flux
of less than 50 kW/m2 (on an inside area basis). The method and/or system
where heating
the feedwater stream to the first feedwater temperature condition includes
providing a first
heating mass flux rate of between about 800 kg/m2/s and about 2,500 kg/m2/s.
The method
and/or system where heating the feedwater stream to the first feedwater
temperature
condition includes heating the feedwater stream in an economizer section of
the steam
generator. The method and/or system where the controlled vapour-enhanced steam
quality
is at least about 3 %, at least about 5 %, at least about 12 %, or between
about 10 % and
about 30 %. The method where the heated vapour-enhanced steam stream has a
heated
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vapour-enhanced steam quality of at least about 70 %, at least about 80 %, or
at least
about 90 %. The method where the controlled vapour-enhanced steam quality, x,
is
controlled so as to satisfy the following condition:
1
x> ____________________________________________ 1
\ 0.9
Bi
-I- 1
.5
, (pG)CI CIL )0.1
\Ghfg I
wherein:
q is the local heat flux expressed in W/m2,
G is the mass flux expressed in kg/m2/s,
hfy is the evaporative enthalpy expressed in J/kg,
PG is the vapour density expressed in kg/m3,
pi, is the liquid density expressed in kg/m3,
pi, is the vapour phase dynamic viscosity expressed in Pas,
pG is the liquid phase dynamic viscosity expressed in Pas, and,
Bi is the boiling index and is 0.00015, or 0.00020, or in the range of 0.00010
to
0.00025.
[0015] The method/system where the steam quality of the heated vapour-
enhanced
steam stream is controlled to satisfy the following condition:
an 0,70
x 0.58exp [0.52 ¨
0.235Wee'17Fr8.37 ( a )
A
PL CIDNB
wherein:
G 2 DE
eG = _____________________________________
PG a
G2
FrG = _______________________________________
PG(PL-PG)gDE'
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q DNB = 0.1314.5hf9 (g(PL-PG )0) 25
and wherein:
x is the steam quality transition to dryout conditions (expressed in mass
fraction);
De is the hydraulic diameter (expressed in m);
FrG is the Froude Number (dimensionless);
g is the acceleration due to gravity (expressed in nn/s2);
q is the local heat flux (expressed in Winn2);
qDNB is the heat flux at departure from nucleate boiling (expressed in W/nn2);
G is the mass flux (expressed in kg/m2/s);
hfg is the evaporative enthalpy (expressed in J/kg);
W eG is Weber Number (dimensionless);
PG is the vapour density (expressed in kg/m3);
PL is the liquid density (expressed in kg/m3); and
6 is the surface tension (expressed in N/nn).
[0016] The method and/or system may be carried out/configured so that
at least a
portion of the heated vapour-enhanced steam stream is recycled to the
auxiliary vapour
stream as a recycled steam stream. The method and/or system where between
about 3%
and about 30% by weight, or between about 5% and about 20% by weight, of the
heated
vapour-enhanced steam stream is recycled to the auxiliary-vapour stream as the
recycled
steam stream. The method and/or system where the recycled steam stream is
compressed
before being combined with the heated feedwater stream. The method further
including
separating the heated vapour-enhanced steam stream into a substantially vapour-
phase
stream and a substantially liquid-phase stream prior to injection of at least
a first portion of
the substantially vapour-phase stream into the hydrocarbon-containing
reservoir. The
method and/or system where a second portion of the substantially vapour-phase
stream is
recycled to the auxiliary vapour stream as a recycled steam stream. The method
and/or
system where the second portion of the substantially vapour-phase stream
accounts for
between about 3% and about 30% by weight of the substantially vapor-phase
stream. The
method and/or system where the substantially vapor-phase stream accounts for
between
about 70% and about 95 %, or between about 80% and about 90%, by weight of the
heated
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vapour-enhanced steam stream. The method and/or system where the substantially
liquid-
phase stream accounts for between about 30% and about 5%, or between about 20%
and
about 10%, by weight of the heated vapour-enhanced steam stream. The method
and/or
system where the controlled injected steam quality is at least about 80%, at
least about
85%, at least about 90%, at least about 95% or about 100%. The method and/or
system
where the hydrocarbon-containing reservoir is a bitumen-containing reservoir.
The method
and/or system where the hydrocarbon production process includes steam assisted
gravity
drainage, cyclic steam stimulation, a solvent driven process, a solvent
dominant process,
or a combination thereof. The method and/or system where the hydrocarbon
production
process includes a SAGD process, the controlled injected steam quality is
between about
85 % and about 100 %, the injected steam is at an injection pressure of
between about 4
MPa and about 11 MPa, and the injected steam is at an injection temperature of
between
about 250 C and about 325 C. The method and/or system where the steam
generator is
heat-recovery steam generator (HRSG). The method and/or system where the HRSG
is a
natural-circulation steam generator (NCSG), forced-circulation steam generator
(FCSG), or
once-through steam generator (OTSG). The method and/or system where the
feedwater
stream has a silica content of less than about 250 mg/L, or less than about 50
mg/L. The
method and/or system where the feedwater stream has a hardness content of less
than
about 25 mg/I, or less than about 15 mg/L. The method and/or system where the
feedwater
stream has a total suspended solids content of less than about 200 mg/L, or
less than about
5 mg/L. The method and/or system where the feedwater stream has a soluble
organics
content of less than about 500 mg/L, or less than about 400 mg/L. The method
and/or
system where the feedwater stream has a residual oil content of less than
about 200 mg/L,
or less than about 2.0 mg/L. The method and/or system where the feedwater
stream has a
turbidity of less than about 250 NTU ppnn, or less than about 5 NTU. The
method and/or
system where the heating of the feedwater stream to the first feedwater
temperature
condition occurs primarily by convective heating and/or substantially in the
absence of
nucleate boiling. The method and/or system where the heating of the vapour-
enhanced
steam stream occurs primarily by radiative heating and/or substantially in the
absence of
nucleate boiling. The method and/or system where combining the heated
feedwater stream
with the auxiliary vapour stream is carried out in an eductor having a motive-
fluid inlet, a
passive-fluid inlet, and a discharge outlet. The method and/or system where
the feedwater
stream enters the eductor at the motive fluid inlet, the auxiliary-vapour
stream enters the
eductor at the passive-fluid inlet, and the vapour-enhanced stream exits the
eductor at the
discharge outlet.
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Approach 2: Utilizing a novel flow-path configuration in combination with a
pressure-
red ucing element
[0017] One general aspect includes a method of generating steam for
use in a
hydrocarbon production process, the method comprising: passing a feedwater
stream from
a first-stage inlet to a first-stage outlet along a first-stage flow path,
wherein along the first-
stage flow path: (i) the feedwater stream is pressurized to a first-stage
pressure, (ii) the
feedwater stream is heated to a first-stage temperature by a first-stage heat
flux, (iii) the
first-temperature is maintained below the saturation temperature of the
feedwater stream,
and (iv) the first-stage flow path is configured to attenuate the first-stage
heat flux as the
feedwater stream approaches the first-stage outlet. The method further
comprises passing
the feedwater stream from the first-stage outlet through a pressure-reducing
element to a
second-stage inlet, wherein the second-stage inlet has a second-stage pressure
that is
sufficiently lower than the first-stage pressure to convert the feedwater
stream into a flashed
stream. The method further comprises passing the flashed stream from the
second-stage
inlet to a second-stage outlet along a second-stage flow path, wherein: (i) at
the second-
stage inlet the flashed stream has a steam quality that exceeds a threshold
for mitigating
nucleate boiling along a heated surface of the second-stage flow path, and
(ii) the flashed
stream is heated along the second-stage flow path by a second-stage heat flux
to increase
the steam quality of the flashed stream. The method further comprises
injecting at least a
portion of the flashed stream into a hydrocarbon-containing reservoir as
injected steam to
facilitate the hydrocarbon production process.
[0018] One general aspect includes a system for generating steam for
a
hydrocarbon production process, the system comprising: (i) a radiant section,
(ii) an
economizer having a lower section that is proximal to the radiant section and
an upper
section that is proximal to the lower section, and (iii) a combustion-gas flow
path that passes
from the radiant section to the lower section of the economizer to the upper
section of the
economizer. The system further comprises a first-stage flow path for passing a
feedwater
stream through at least a portion of the steam generator from a first-stage
inlet to a first-
stage outlet, wherein along the first-stage flow path: (i) the feedwater
stream is pressurized
to a first-stage pressure by a pressurizing element, (ii) the feedwater stream
is heated to a
first-stage temperature by a first-stage heat flux, (iii) the first-
temperature is maintained
below the saturation temperature of the feedwater stream, and (iv) at least
part of the first-
stage flow path is co-current with the combustion-gas flow path as the
feedwater stream
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approaches the first-stage outlet. The system further comprises a pressure-
reducing
element that connects the first-stage outlet to a second-stage inlet, wherein
the pressure-
reducing element is configured to reduce the first-stage pressure to a second-
stage
pressure that is sufficiently lower than the first-stage pressure to convert
the feedwater
stream into a flashed stream. The system further comprises a second-stage flow
path for
passing the flashed stream through at least a portion of the steam generator
from the
second-stage inlet to a second-stage outlet, wherein: (i) at the second-stage
inlet the
flashed stream has a steam quality that exceeds a threshold for mitigating
nucleate boiling
along a heated surface of the second-stage flow path, and (ii) the flashed
stream is heated
along the second-stage flow path by a second-stage heat flux to increase the
steam quality
of the flashed stream. The system further comprises a steam injection section
configured
to inject at least a portion of the flashed steam stream into a hydrocarbon-
containing
reservoir as injected steam at a controlled injected steam quality to
facilitate the
hydrocarbon production process.
[0019] Implementations may include one or more of the following features.
The
method and/or system where the first-stage flow path is co-current with a
combustion-gas
flow path as the feedwater stream approaches the first-stage outlet. The
method and/or
system where, as the feedwater stream approaches the first-stage outlet, the
first-stage
flow path comprises bare tube. The method and/or system where the feedwater
stream
approaches the first-stage outlet in a lower section of an economizer. The
method and/or
system where the feedwater stream approaches the first-stage outlet after
passing through
a radiant section. The method and/or system where the feedwater stream passes
through
an upper section of an economizer before passing through the radiant section.
The method
and/or system where, as the first-stage flow path passes through the radiant
section, the
first-stage average heat flux is between: (i) about 40 kW/m2 and about 100
kW/m2; and/or
(ii) about 50 kW/m2 and about 90 kW/m2, on an inside area basis. The method
and/or
system where, as the first-stage flow path passes through the shock row of the
lower
section of the economizer, the first-stage average heat flux in the lower
section is between:
(i) about 65 kW/m2 and about 135 kW/m2; and/or (ii) about 75 kW/m2 and about
120 kW/m2,
on an inside basis. The method and/or system where, as the first-stage flow
path passes
through the fifth row of the lower section of the economizer, the first-stage
average heat
flux in the lower section is between: (i) about 25 kW/m2 and about 75 kW/m2;
and/or (ii)
about 35 kW/m2 and about 65 kW/m2, on an inside basis. The method and/or
system where,
as the first-stage flow path passes through the first finned row in the upper
section of the
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economizer, the first-stage average heat flux in the upper section is between:
(i) about 85
kW/m2 and about 220 kW/m2; and/or (ii) about 110 kW/m2 and about 200 kW/m2, on
an
inside basis. The method and/or system where, as the first-stage flow path
passes through
the last finned row in the upper section of the economizer, the first-stage
average heat flux
in the upper section is between: (i) about 2 kW/m2 and about 12 kW/m2; and/or
(ii) about 3
kW/m2 and about 10 kW/m2, on an inside basis..
[0020] The method and/or system where the steam quality of the
flashed stream is
controlled to satisfy the following condition:
pG) ¨)0.25 q 0.70
0.58exp [0.52 ¨ 0.235Wee17F4.37(¨
PL (IDNB
wherein:
G 2 D,
= ________________________________________ WeG =
PG a
G2
FrG = ______________________________________
PG(PL-Pc)gDE'
q DNB = 0.131pt 5hf9(g(PL-PG)o)025
and where:
x is the steam quality transition to dryout conditions (expressed in mass
fraction);
De is the hydraulic diameter (expressed in m);
FrG is the Froude Number (dimensionless);
g is the acceleration due to gravity (expressed in m/52);
q is the local heat flux (expressed in W/m2);
(1DNB is the heat flux at departure from nucleate boiling (expressed in W/m2);
G is the mass flux (expressed in kg/m2/s);
hro, is the evaporative enthalpy (expressed in J/kg);
W eG is Weber Number (dimensionless);
PG is the vapour density (expressed in kg/m3);
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PL is the liquid density (expressed in kg/m3); and
a is the surface tension (expressed in N/m).
[0021] The method and/or system where the first-stage pressure is
between about
15 MPa and about 22 MPa. The method and/or system where second-stage pressure
is
between about 4 MPa and about 11 MPa. The method and/or system where the first-
stage
temperature is between about 340 C and about 360 C at the first-stage
outlet. The method
and/or system where the first-stage temperature is at least about 3 C, 10 C,
15 C, or 20
C subcooled as the feedwater stream approaches the first-stage outlet. The
method and/or
system where as the feedwater stream approaches the first-stage outlet the
first-stage
temperature is subcooled by a subcool, AT, that satisfies the following
condition:
p0.0239
5 (q 2.83
AT > ______________________________
0 8 0 4 k 9 1100176 p1.156)
0.023R, 7
where:
q is a local heat flux expressed in W/m2,
Re is a Reynolds number,
Pr is a Prandtl number,
k is a fluid thermal conductivity expressed in W/m/ C,
De is a hydraulic diameter, and
P is a system pressure expressed in Pa.
[0022] The method and/or system where the steam quality of the
flashed stream at
the second-stage inlet is at least about 3 %, at least about 5 %, at least
about 12 %, or
between about 10 % and about 20 %. The method and/or system where the flashed
stream
has a steam quality of at least about 70%, at least about 80%, or at least
about 90% at the
second-stage outlet. The method and/or system where the steam quality, x, of
the flashed
stream is controlled so as to satisfy the following condition at the second-
stage inlet:
1
x > _________________________________________ 1
\ 0.9
Bi
q 0945 3 )0.1
t + 1 \Ghfy\pLl \LI
, GI /
wherein:
13
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q is a local heat flux expressed in W/m2,
G is a mass flux expressed in kg/m2/s,
hfg is a evaporative enthalpy expressed in J/kg,
PG is a vapour density expressed in kg/m3,
pi, is a liquid density expressed in kg/m3,
[IL is a vapour phase dynamic viscosity expressed in Pas,
tiG is a liquid phase dynamic viscosity expressed in Pas, and
Bi is a boiling index and is 0.00015, or 0.00020, or in the range of
0.00010 to 0.00025.
[0023] The method and/or system where the steam quality of the
portion of the
flashed stream that is injected into the hydrocarbon-containing reservoir is
at least about
80%, at least about 85%, at least about 90%, at least about 95%, or about
100%. The
method and/or system where hydrocarbon-containing reservoir is a bitumen-
containing
reservoir. The method and/or system where the hydrocarbon production process
comprises
steam assisted gravity drainage, cyclic steam stimulation, a solvent driven
process, a
solvent dominant process, or a combination thereof. The method and/or system
where the
hydrocarbon production process comprises a SAGD process, the controlled
injected steam
quality is between about 85% and about 100%, the injected steam is at an
injection
pressure of between about 4 MPa and about 11 MPa, and the injected steam is at
an
injection temperature of between about 250 C and about 325 C. The method
and/or
system where the feedwater stream has a silica content of less than about 250
mg/L, or
less than about 50 mg/L. The method and/or system where the feedwater stream
has a
hardness content of less than about 25 mg/L, or less than about 15 mg/L. The
method
and/or system where the feedwater stream has a total suspended solids content
of less
than about 200 mg/L, or less than about 5 mg/L. The method and/or system where
wherein
the feedwater stream has a soluble organics content of less than about 500
mg/L, or less
than about 400 mg/L. The method and/or system where the feedwater stream has a
residual oil content of less than about 200 mg/L, or less than about 2.0 mg/L.
The method
and/or system where the feedwater stream has a turbidity of less than about
250 NTU ppm,
or less than about 5 NTU.
14
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BRIEF DESCRIPTION OF THE DRAWINGS
[0024] These and other features of the present disclosure will become
more
apparent in the following detailed description in which reference is made to
the appended
drawings. The appended drawings illustrate one or more embodiments of the
present
disclosure by way of example only and are not to be construed as limiting the
scope of the
present disclosure.
[0025] FIG. 1 provides a schematic plot of various heat transfer
mechanisms as the
water passes through a heated boiler tube.
[0026] FIG. 2 provides a schematic of a system for generating steam
for a thermal
process for hydrocarbon recovery in accordance with select embodiments of the
present
disclosure.
[0027] FIG. 3A provides a schematic of an eductor which may be
utilized as a
stream connector and a pressure-reducing element in accordance with select
embodiments
of the present disclosure. FIG. 3B provides estimated ideal discharge
parameters from the
eductor of FIG. 3A. FIG. 3C provides parameters relating to the quantity of
the auxiliary-
vapour stream, relative to the feedwater stream inlet flow rate. FIG. 3D
provides parameters
relating to the quantity of (simple) flash steam created by reducing the
feedwater-stream
pressure to the steam-enhanced stream pressure at the outlet of the eductor in
the absence
of any contribution from the auxiliary-vapour stream.
[0028] FIG. 4 provides a plot of heat flux at the transition into the
nucleate boiling
heat transfer regime as a function of the difference between the local fluid
temperature and
the local saturation temperature (i.e. the degree of subcool) for a series of
different
saturation temperatures.
[0029] FIG. 5 provides a plot of heat flux at the transition out of
the nucleate boiling
regime as a function of steam quality at the transition out of the nucleate
boiling heat
transfer regime for a series of different saturation temperatures and fluid
flow rates.
[0030] FIG. 6 provides a scatter plot of typical normal peak
operating heat flux
values based on the external surface area of the finned-tube component of an
archetypal
boiler or HRSG.
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[0031] FIG. 7 provides a scatter plot of peak heat flux values on an
inside area of
the finned-tube component of an archetypal boiler or HRSG.
[0032] FIG. 8 provides a scatter plot of typical normal peak
operating heat flux
values based on the external surface area for radiant and shock tube
components of typical
boiler or HRSG.
[0033] FIG. 9 provides a scatter plot of peak heat flux values for
the same
configurations on an inside area basis diameter for radiant and shock tube
components of
typical boiler or HRSG.
[0034] FIG. 10 provides a plot of the maximum subcool required for
subcooled
nucleate boiling for NPS 3 S160 pipe coil under archetypal conditions.
[0035] FIG. 11 provides a further plot of the maximum subcool
required for
subcooled nucleate boiling for NPS 3 S160 pipe coil under archetypal
conditions.
[0036] FIG. 12 provides a plot of the minimum steam quality required
for forced
convective evaporation under archetypal conditions.
[0037] FIG. 13 provides a plot of the minimum steam quality required for
forced
convective evaporation under archetypal conditions.
[0038] FIG. 14 shows a schematic of an OTSG configured with a novel
flow-path in
combination with a pressure-reducing element in accordance with a method
and/or system
of the present disclosure.
[0039] FIG. 15A and FIG. 15B show plots of feedwater stream flowrate as a
function of steam quality at dryout based on a steam-injection temperature at
about 310 C
for two common coils.
[0040] FIG. 16A and FIG. 16B show plots of flowrate as a function of
minimum
steam quality for an archetypal set of steam-generator parameters.
[0041] FIG. 17A ¨ FIG. 17D show plots of steam quality at the second-stage
inlet
as a function of the first-stage pressure for an archetypal set of steam-
generator
parameters.
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[0042] FIG. 18A and FIG. 18B, show plots of minimum subcool as a
function of
heat flux at first-stage pressures for an archetypal set of steam-generator
parameters.
[0043] FIG.19 shows plots of heat flux across a set of economizer
rows (1 = shock
row) for a series of archetypal heat-release profiles.
[0044] FIG. 20 shows plots of various operating conditions in the context
of a
conventional OTSG design.
[0045] FIG. 21 shows plots of various operating conditions in the
context an OTSG
configured with a novel flow-path in combination with a pressure-reducing
element in
accordance with a method and/or system of the present disclosure.
DETAILED DESCRIPTION
[0046] Thermal processes for hydrocarbon recovery often require high-
quality,
high-temperature, and high-pressure steam. For example, SAGD processes may
employ
steam having a quality of between about 85 % and about 100 cY0, a pressure of
between
about 4,000 kPa and about 11,000 kPa, and a temperature of between about 250
C and
about 325 C. Heat-recovery steam generators (HRSG(s)) are often used to
provide steam
for such processes. HRSG(s) are typically classified as forced-circulation
steam generators
(FCSG(s)), or once-through steam generators (OTSG(s)). Because OTSGs are the
type of
HRSG that is most commonly used in hydrocarbon recovery operations, the
methods and
systems of the present disclosure are discussed within OTSG-related
frameworks.
However, those skilled in the art having benefited from the teachings of the
present
disclosure will appreciate how the methods and systems of the present
disclosure apply to
NCSGs, FCSGs, or HRSGs more generally.
[0047] OTSGs are large, continuous-tube type steam generators.
Feedwater is
supplied at one end of the tube, and it is heated (and eventually converted to
steam) as it
travels in a single pass along the tube. OTSGs typically comprises of a
multitude of parallel
flow passes to accommodate the total flowrate within a given tube size. OTSGs
typically
comprise of a convection section (also called an economizer section or an
economizer) and
a radiant section. In the convection section, the feedwater is preheated by
heat exchange
with a hot combustion gas (usually flue gas). In the radiant section, the
feedwater is heated
more aggressively by a high-powered furnace.
17
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[0048] The methods and systems disclosed herein utilize a two-stage
steam
generation strategy that attenuates steam generator fouling by mitigating
(i.e. reducing or
eliminating) nucleate boiling on super heated surfaces within the steam
generator. In the
first stage, operational parameters are controlled to ensure the feedwater
stream is
pressurized and heated under conditions that are not sufficient to induce
subcooled
nucleate boiling. The subcool of the feedwater stream (i.e. the difference
between the local
temperature of the feedwater stream and its local saturation temperature) in
the economizer
section is a critical parameter in this respect. The subcool of the feedwater
stream is
selected to ensure heat transfer occurs by convective heat transfer. In the
second stage,
operational parameters are controlled to ensure that heating in the radiant
section occurs
by forced convective evaporation such that the saturated nucleate boiling
regime is
substantially avoided. The steam quality of the fluid is a critical parameter
in this respect.
[0049] The present disclosure provides two approaches to generating
steam while
mitigating nucleate boiling. In one approach, as the feedwater stream
approaches the
saturated nucleate boiling regime, an auxiliary-steam stream is utilized to
boost the steam
quality above the threshold required to enter the convective evaporation heat
transfer
regime. In the other approach, an atypical flow-path is coupled with a
pressure-reducing
element to the same effect. While the two approaches can be combined, the
present
disclosure outlines them independently for sake of clarity. Those skilled in
the art having
benefited from the teachings of the present disclosure will appreciate how the
two
approaches can be combined in one steam generator. While the two approaches
are
outlined independently, there is substantial overlap between the two
approaches ¨ many
of the teachings (e.g. terms, concepts, equations, and/or the like) set out
for one approach
may apply to the other. Those skilled in the art having benefited from the
teachings of the
present disclosure will readily appreciate such overlaps and how they can be
applied to
practice the systems and methods of the present disclosure.
[0050] Select embodiments of the present disclosure will now be
described with
reference to FIG. 1 ¨ FIG. 30. FIG. 1 ¨ FIG. 30 illustrate aspects of one or
more
embodiments of the present disclosure by way of example only and are not to be
construed
as limiting the scope of the present disclosure.
18
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Approach 1: Utilizing an auxiliary-vapour stream
[0051] Select embodiments of the systems and methods of the present
disclosure
utilize an auxiliary-vapour stream to meet or exceed the threshold for film
boiling at the
second pressure/temperature condition. The feedwater stream and the auxiliary-
vapour
stream are connected in a "stream connector" which may be a simple 3-way
connector, a
valve, a pressure reducer (such as eductor), or the like. Analysis shows that
absent an
enhancement in steam quality from the auxiliary-vapour stream (or a
substantial
reconfiguration of the flow path), substantial pressure drops are required to
obtain sufficient
steam quality to ensure forced convective evaporation under typical operation
conditions.
Such pressure drops may not be feasible from an operations perspective and/or
they may
be excessively inefficient. By utilizing the auxiliary-vapour stream in the
second stage, the
systems and methods of the present disclosure provide a means of minimizing or
eliminating the pressure drop required at the second stage. This provides for
improved
energetic efficiencies and allows for greater latitude in setting the
parameters of the first
stage. Taken together, the first stage and the second stage provide a process
with
improved efficiency for generating steam from feedwater streams that would not
be suitable
for steam generation using standard protocols.
[0052] Select embodiments of the present disclosure relate to a
feedwater stream.
The feedwater stream may comprise fluids from a produced emulsion that has
been
subjected to coarse oil-water separation (such as by degassing, treating,
and/or free water
knockout), or not. Optionally, fluids from the produced emulsion may be de-
oiled but
otherwise untreated to form the feedwater stream. Alternatively, fluids from
the produced
emulsion may be minimally treated, or heavily treated. In the context of the
present
disclosure, de-oiling may involve passing fluids from the produced emulsion
through a
gravity separator (such as a skim tank), a flotation-type unit (such as a
compact flotation
unit), and/or a filtration-type unit (such as an oil removal filter).
[0053] In select embodiments, the feedwater stream may have a
residual oil
content of less than about 200 nng/L (preferably less than about 2.0 mg/L).
The feedwater
stream may have a turbidity of less than about 250 NTU ppnn (preferably less
than about 5
NTU). The feedwater stream may have a silica content of less than about 250
nng/L
(preferably less than about 50 mg/L). The feedwater stream may have a hardness
content
of less than about 25 nng/L (preferably less than about 15 mg/L). The
feedwater stream
may have a total suspended solids content of less than about 200 nng/L
(preferably less
19
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A8141946CA
than about 5 ring/L). The feedwater stream may have a soluble organics content
of less
than about 500 ring/L (preferably less than about 400 ring/L). Those skilled
in the art having
benefited from the teachings of the present disclosure will readily appreciate
the standard
techniques and equipment used to determine the residual oil content, the
turbidity, the silica
content, the hardness content, the total suspended solids content, and/or the
soluble
organics content of a feedwater stream.
[0054] In select embodiments of the present disclosure, the feedwater
stream is
pressurized to a first pressure condition that is in part dependent upon the
second pressure
condition, in the sense that the difference between the first and second
pressure conditions
will provide the available scope for flash steam generation by pressure
reduction. For
example, assuming a second pressure condition of approximately 9,500 kPa, the
first
pressure condition feedwater may have a pressure of at least about 12,500 kPa
(preferably
at least about 14,500 kPa), to yield a desired amount of flash steam. In the
context of
present disclosure, the feedwater may be pressurized to the first pressure
condition by a
pressurizing element such as a pump. The system pressure is increased to the
extent that
the feedwater can remain in liquid phase without boiling when being heated.
Also, the
system pressure may only be increased to the extent commercially feasible with
existing
piping components and materials. In select embodiments of the present
disclosure, the use
of solvents and/or generation of the steam at a pad for injection (instead of
at a central
processing facility) may require lower pressure steam such that the second
pressure
condition may be at least about 5,000 kPa or at least about 3,500 kPa.
[0055] In select embodiments of the present disclosure, the feedwater
stream may
be heated to a first temperature condition. The first temperature condition is
referenced by
the subcool temperature. The subcool temperature is the difference between the
boiling
point temperature at the local operating pressure and the bulk fluid
temperature. At the first
temperature condition, the feedwater may have a subcool temperature of between
about
10 C and about 40 C (preferably between about 20 C and about 30 C).
Heating the
feedwater stream to the first temperature condition may comprise providing a
peak heat
flux of between about 150 kW/m2 and about 300 kW/m2 (on an inside area basis).
In the
context of the present disclosure, "heat flux" is the rate of heat energy
transfer through a
given surface, in other words, the heat rate per unit area on an inside
surface area basis.
As will be appreciated by those skilled in the art having benefited from the
teachings of the
present disclosure, there may be variation of the heat flux around the
circumference of the
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A8141946CA
tube, as well as along the longitudinal axis ¨ and the peak heat flux refers
to the maximum
local heat flux at a given point along the circumference. Another measure is
the average
heat flux, which typically refers to the local average heat flux around the
circumference.
Typically, the local peak heat flux is 1.4 to 2.6 times the average heat flux,
depending on
tube geometry and other factors.
[0056] Heating the feedwater stream to the first temperature
condition may occur
primarily by forced convective heating. Heating the feedwater stream to the
first
temperature condition may occur in a convective-section of a steam generator
such as in
an economizer. In the context of the present disclosure, an economizer
comprises one or
more devices configured to reduce energy consumption in a steam-generating
operation
by preheating feedwater. Typically, an economizer comprises a heat exchanger
in which
thermal energy is transferred from a high-temperature fluid (e.g., steam
condensate or flue
gas) to the feedwater such that less energy is required to vaporize it.
Economizers may be
mechanical devices intended to reduce energy consumption or to perform another
useful
functions such as preheating a fluid. Economizers are typically fitted to a
boiler, and they
may save energy by using, for example, the exhaust gases from the boiler to
preheat cold
feedwater. In the context of the present disclosure, the economizer may occur
downstream
of the pressurizing element, or the economizer and the pressurizing element
may be
integrated.
[0057] As will be appreciated by those skilled in the art having benefited
from the
teachings of the present disclosure, economizers typically use extended heat
transfer
surfaces, such as solid or serrated fins, to improve the heat extraction from
the hot fluid.
The tubes in contact with the hottest fluid are typically bare tubes, and fins
are provided to
the outside of the tubes to increase the local heat flux at points contacting
the hot fluid after
the initial heat transfer to the bare tubes. Fins are available in a multitude
of diameters and
spacing and can be selected to manage heat flux rate throughout the
economizer. The
location of subcooled boiling is a function of the local peak heat flux, the
thernno-physical
properties of the fluid, the fluid velocity, tube diameter, and the amount of
subcool of the
fluid. High local peak heat flux requires a larger amount of subcool than a
lower local peak
heat flux with all other variables equal, to prevent subcooled nucleate
boiling. By judicious
use of fin profiles throughout the economizer, the local peak heat flux can be
managed to
maintain sufficient subcool temperature to prevent subcooled boiling and the
associated
high fouling rate.
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[0058] In select embodiments of the present disclosure, at the first
temperature
condition, the feedwater stream operates at a maximum temperature such that
the subcool
is at least about 10 C (preferably by between about 20 C and about 30 C) to
substantially
prevent subcooled nucleate boiling. The extent of subcool of a feedwater
stream and the
operational parameters required to substantially prevent nucleate boiling may
be
determined, for example, using the Bergles-Rohsenow correlation, the Yin
correlation, the
Thom correlation, the Dittus-Boelter correlation, the Sieder-Tate correlation,
the Gnielinski
correlation, or any other appropriate correlation or combination thereof. In
select
embodiments of the present disclosure, one or more of the foregoing
correlations may be
used in a form suitable for a single phase or a two-phase (liquid/gas) system.
[0059] The onset of nucleate boiling (ONB) temperature is generally
determined by
the solution of two equations. One equation relates the heat flux at ONB to
the wall
superheat (i.e. the difference between the temperature of the inside pipe
surface and the
local saturation boiling point of the water). The second equation relates the
heat flux to the
difference between the inside pipe wall temperature and the bulk fluid
temperature, the
flowing conditions and thernno-physical properties of the fluid, and the tube
geometry. Two
such equations are the Bergles-Rohsenow and the Dittus-Boelter equation.
[0060] The Bergles-Rohsenow equation provides a relationship between
the heat
flux (q), and the wall superheat at the ONB. The Bergles-Rohsenow correlation
is shown in
EQN. 1.
2.83
q = .0017 6P1.156 U(T ¨ T5)}P"234 EQN. 1
wherein: Tw and T, are the inside wall temperature and local saturation
temperature (in C)
respectively; q is the heat flux necessary to cause nucleate boiling (in
Winn2); and P is the
system pressure (in Pa).
[0061] The Dittus-Boelter correlation provides a relationship between the
heat flux
(q) and the temperature difference between the pipe wall (Tw) and the bulk
fluid temperature
(Tb). The Dittus-Boelter correlation is shown in EQN. 2.
q = 0.023 Re 0.8 pr 0.4 iTk f(Tw ¨ T5) + (T, ¨ Tb)) EQN. 2
22
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A8141946CA
wherein: q is the local heat flux (in Wirn2), Re is the Reynolds number, Pr is
the Prandtl
number, k is the fluid thermal conductivity (in Wirn/ C), De is the hydraulic
diameter, which is
the inside diameter for pipe (in m), Tw, T, and Tb are the wall temperature,
saturation
temperature and bulk fluid temperature (in C) respectively. The fluid
properties are evaluated
at the film temperature, which is defined in EQN 3.
if= Tw +Tb
EQN. 3
2
wherein: Tf, Tw and Tb are the film temperature, wall temperature and bulk
fluid temperature
(in C) respectively.
[0062] Select embodiments of the present disclosure comprise
combining the
feedwater stream with an auxiliary-vapour stream to form a vapour-enhanced
stream at a
second pressure condition and a second temperature condition. The vapour-
enhanced
stream may have a steam quality of at least about 3 % (preferably at least
about 5 c/o) to
mitigate against nucleate boiling during further heating. At the second
pressure condition,
the vapour-enhanced stream may have a pressure of between about 3 MPa and
about 12
MPa. At the second temperature condition, the vapour-enhanced stream may have
a
temperature of between about 234 C and about 325 C. Prior to combining the
feedwater
stream with the auxiliary-vapour stream, the auxiliary-vapour stream may have
a pressure
of between about 2 MPa and about 10 MPa. Prior to combining the feedwater
stream with
the auxiliary-vapour stream, the auxiliary-vapour stream may have a
temperature of
between about 212 C and about 311 C. Prior to combining the feedwater stream
with the
auxiliary-vapour stream, the auxiliary-vapour stream may have a steam quality
of between
about 90 % and about 100 c/o.
[0063] EQN. 2 indicates that heat flux increases with increasing
fluid velocity (i.e.
an increasing Reynolds number) and with increasing bulk fluid subcool
operating
temperature (i.e. (T, ¨ Tb)). For a given wall superheat, operating flowrate,
pressure and
geometry, the bulk fluid subcool temperature can be determined that will
result in the onset
of nucleate boiling.
[0064] In select embodiments of the present disclosure, the combining
of the
feedwater stream with the auxiliary-vapour stream to form the vapour-enhanced
stream at
the second pressure condition and the second temperature condition may be
couple with
a pressure reduction facilitated by a pressure reducing agent such as an
eductor. Those
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skilled in the art having benefited from the teachings of the present
disclosure will
appreciate that eductors are used in other industry processes and often
referred to by
alternate names such as "ejector", "jet compressor" and "jet pump". In the
context of the
present disclosure, an eductor is a device that combines a motive fluid (under
a higher
pressure condition) with a passive fluid (at a lower pressure condition) and
discharges the
fluids as a mixture of the fluids (at a pressure between the motive fluid
pressure and the
passive fluid pressure). In the context of the present disclosure the terms
"eductor", "ejector", "jet compressor", and/or "jet pump" do not imply any
particular phase
of the motive fluid and/or the passive fluid.
[0065] In select embodiments of the present disclosure, the eductor is
configured
such that at least a portion of the feedwater stream is converted to flash
steam. In the
context of the present disclosure, "flash steam" refers to steam formed when
high-
temperature condensate is subjected to a rapid pressure reduction. Those
skilled in the art
having benefited from the teachings of the present disclosure will recognize
that flash steam
is just a convenient name used to explain how the steam is formed, and that it
does not
imply a unique steam composition. Briefly stated, high temperature condensate
stores
latent energy that cannot be retained at lower pressure. When subjected to a
pressure drop,
some of the excess energy causes a percentage of the condensate to flash to
the vapor
phase. This process contributes to the steam quality of the steam-enhanced
stream which
may provide operational flexibility with respect to the parameters associated
with the
contribution from the auxiliary-vapour stream.
[0066] In the context of the present disclosure, the steam quality of
the steam-
enhanced steam is "enhanced" (i.e. boosted) in that it has a greater steam
quality than it
would be but for the contribution of the auxiliary-vapour stream. In select
embodiments of
the present disclosure, at the second pressure condition and the second
temperature
condition, the vapour-enhanced stream has a steam quality of at least about 3
% (preferably
between about 10 % and about 20 cY0) to substantially prevent nucleate boiling
during the
heating of the steam-enhanced stream. In the context of the present
disclosure, steam
quality is the mass fraction of vapor.
[0067] In select embodiments of the present disclosure, the steam quality
required
to substantially prevent nucleate boiling may be determined, for example, by
using the
boiling index, the boiling number, the Lockhart-Martinelli correlation, the
Chen correlation,
or a combination thereof.
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The boiling index may be as shown in EQN. 4
B, = B, * X EQN. 4
wherein: B, is the boiling index (dimensionless); B, is the boiling number;
and X is the
Lockhart-Martinelli parameter.
[0068] The boiling number, B,, may be as shown in EQN. 5
Bo = q/(Ghfy ) EQN. 5
wherein: q is the heat flux (in W/m2); G is the mass flux (Le. the mass rate
divided by the
flowing cross sectional area of the tube) of the two phase system (in
kg/m2/s); and hfy is the
evaporative enthalpy (i.e. the difference in enthalpy between saturated vapor
and saturated
.. liquid at the pressure or temperature owing condition) (in J/kg).
[0069] The
Lockhart-Martinelli number for turbulent/turbulent flow regime can be
estimated by the correlation shown in EQN. 6.
/x\ " f/
pLS /400.1
xtt 1¨ EQN. 6
PL
Wherein: Xttis the Lockhart-Martinelli number for the turbulent-turbulent flow
regime; x is the
steam quality, pG and pi, are the vapour and liquid phase dynamic viscosity,
respectively (in
Pas); and PG and pi, are the vapour and liquid density, respectively (in
kg/m3).
[0070] EQN. 6
indicates that, for a given boiler operating condition, the Lockhart-
Martinelli number is large at low steam qualities (i.e. as x approaches zero)
and decreases
as the steam quality increases (i.e. as 1-x approaches zero). This causes the
boiling index
to decrease with an increase in steam quality. At high boiling index numbers
(low steam
qualities), nucleate boiling is the dominant heat transfer mechanism. At low
boiling index
numbers (high steam qualities), forced convective evaporation is the dominant
heat transfer
mechanism. A typical criterion for the transition from nucleate boiling to
convective
evaporation is in the range of about B, < 0.00010 to B, < 0.00025.
[0071] Select
embodiments of the present disclosure comprise heating the vapour-
enhanced stream to increase the steam quality thereof. The heating of the
vapour-
enhanced stream may occur primarily by radiative heating, for example in a
radiant-heating
Date Recue/Date Received 2020-05-13
A8141946CA
section of steam generator; or primarily convective heating, for example in a
section of the
economizer, which is a combination of convective and radiant heat transfer
from the flue
gases, with the radiant component decreasing as the flue gas temperature
decreases; or
by some combination of thereof. In the context of the present disclosure,
"radiant-heating
section" refers to the section in a steam generator where the heating of the
vapour-
enhanced stream is primarily achieved by radiant heat transfer.
[0072] In select embodiments of the present disclosure, the heating
of the vapour-
enhanced stream may comprise providing an average heat flux of between about
50 kW/m2
and about 160 kW/rn2(on an inside area basis), and a peak heat flux of between
about 150
kW/m2 and 300 kW/m2 (on an inside area basis). After heating the vapour-
enhanced
stream, the steam-enhanced stream may have a steam quality of between about 70
% and
about 100%.
[0073] Select embodiments of the present disclosure comprise
injecting at least a
portion of the steam-enhanced stream into a hydrocarbon-containing reservoir.
In the
context of the present disclosure, 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. In the context of the
present disclosure,
petroleum is a naturally occurring mixture consisting predominantly of
hydrocarbons in the
gaseous, liquid, or solid phase. In the context of the present disclosure, the
words
"petroleum" and "hydrocarbon(s)" 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. In the context of the present disclosure,
"fluids", such as
petroleum fluids, include both liquids and gases. 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
26
Date Recue/Date Received 2020-05-13
A8141946CA
density greater than about 1,000 kg/nn3 and a viscosity greater than 10,000
centipoise (cP;
or 10 Pa s) nneasured at original tennperature in the deposit and atnnospheric
pressure, on
a gas-free basis. Although these ternns are in connnnon use, references to
heavy oil and
bitunnen represent categories of convenience, and there is a continuunn of
properties
between heavy oil and bitunnen. Accordingly, references to heavy oil and/or
bitunnen herein
include the continuunn of such substances, and do not innply the existence of
sonne fixed
and universally recognized boundary between the two substances. In particular,
the ternn
"heavy oil" includes within its scope all "bitunnen" including hydrocarbons
that are present
in senni-solid or solid fornn.
[0074] In select ennbodinnents of the present disclosure, at least a
portion of the
steann-enhanced streann is injected into the reservoir to facilitate thernnal
recovery.
"Thernnal recovery" or "thernnal stinnulation" refers to enhanced oil recovery
techniques that
involve delivering thernnal energy to a petroleunn resource, for exannple to a
heavy oil
reservoir. There are a significant nunnber of thernnal recovery techniques
other than SAGD,
such as cyclic steann stinnulation (CSS), solvent-aided processes (SAP),
solvent-driven
processes (SDP), in-situ connbustion, hot water flooding, steann flooding, and
electrical
heating. In general, thernnal energy is provided to reduce the viscosity of
the petroleunn to
facilitate production. This thernnal energy nnay be provided by a "thernnal
recovery fluid",
which is a fluid that carries thernnal energy, for exannple in the fornn of
steann, solvents, or
nnixtures thereof (with or without additives such as surfactants).
[0075] In select ennbodinnents of the present disclosure, a portion
of the steann-
enhanced streann nnay be recycled to fornn the auxiliary-vapour streann. For
exannple,
between about 3 % and about 30 % (preferably between about 5 % and about 20 %)
by
weight of the steann-enhanced streann nnay be recycled to fornn the auxiliary-
vapour streann.
Alternatively, the auxiliary-vapour streann nnay be provided fronn an
auxiliary steann-
generation systenn. The auxiliary steann-generation systenn nnay be
substantially snnaller in
scale than the prinnary steann-generation systenn, and it nnay be configured
to optinnize the
relevant paranneters of the auxiliary-vapour streann (such as steann quality,
inlet pressure,
and/or tennperature). Such optinnizations are within the purview of those
skilled in the art
having benefited fronn the teachings of the present disclosure. The auxiliary-
vapour
generation systenn nnay be configured to generate the auxiliary-vapour streann
fronn a
source that is not derived fronn a produced fluid or fronn a source that is
derived fronn a
produced fluid but that has been treated.
27
Date Recue/Date Received 2020-05-13
A8141946CA
[0076] Select embodiments of the present disclosure may further
comprise
separating the steam-enhanced stream into a substantially vapor-phase stream
and a
substantially liquid-phase stream prior to injection into the hydrocarbon-
containing
reservoir. For example, the steam-enhanced stream may be separated such that
the
substantially vapor-phase stream accounts for between about 70 % and about 95
%
(preferably between about 80 % and about 90 %) of the steam-enhanced stream,
and the
substantially liquid-phase stream may account for between about 30 % and about
5 %
(preferably between about 20 % and about 10 %) by weight of the steam-enhanced
stream.
The liquid-phase stream may for example be treated to provide a feedwater, or
directed to
disposal or an alternative use. A portion of the substantially vapor-phase
stream may be
recycled to form the auxiliary-vapour stream. For example, between about 3 %
and about
30 % by weight of the substantially vapor-phase stream may be recycled to form
the
auxiliary-vapour stream.
[0077] In select embodiments of the present disclosure, the
separating of the
steam-enhanced stream into the substantially vapor-phase stream and the
substantially
liquid-phase stream may occur in a separator. The separator may be, for
example, a flash
vessel. In the context of the present disclosure, a flash vessel is one which
is configured to
separate steam from condensate. In a typical flash vessel, condensate and
steam enter as
a two-phase mixture, and the condensate is separated by gravity or centrifugal
forces and
collected from the base of the vessel while the steam is collected from the
top of the vessel
after possibly passing through a device to further remove entrained condensate
droplets.
In the context of the present disclosure, the collected condensate may be
recycled into the
feedwater stream, for example upstream of the pressurizing element, or simply
disposed.
The collected steam in the vessel is piped from the top of the vessel to any
appropriate
pressure steam equipment or routed directly into the wellbore.
[0078] FIG. 1 is a schematic diagram showing variations in the bulk
temperature
100 (Tb) and wall temperature 102 (T) as water is heated through a boiler tube
104. In
FIG. 1, schematic points in the heat transfer mechanism are indicated with
reference
numbers 106-120.
[0079] Between point 106 and 108, Tõõ is lower than the saturation
temperature (7'0.
Therefore, ordinary convective heat transfer is likely to occur between the
wall and the
liquid in this zone. The same is observed between point 108 and point 110,
where the wall
superheat, (AT = Tw ¨ Ts), is insufficient to activate nucleation centers. The
first vapor
28
Date Recue/Date Received 2020-05-13
A8141946CA
bubbles appear on the wall at point 110. The degree of the wall overheating
needed for
incipient boiling depends on the thernno-physical properties of the fluid,
tube geometry, local
values of heat flux, mass velocity, and the quantity of subcooling. Despite
overheating of
the liquid layers near the hot wall, the bulk flow temperature at point 110
remains lower
than Ts. As a result, so-called "surface boiling" or "subcooled boiling" may
be observed. In
this region, bubbles may form on the wall and condense into the bulk fluid.
[0080] In FIG. 1, The subcooled boiling zone extends up to point 112
where Ts = Tb
and the steam quality is zero (i.e. x = 0). At point 112, x = (h ¨ hL)/hLG,
where h is the bulk
enthalpy of the fluid, hi, the saturated liquid enthalpy on the saturation
line, and hLG is the
latent heat of vaporization. The zone of saturated nucleate boiling follows
point 112, when
Ts = Tb and x> 0. Initially, the vapor bubbles in subcooled boiling (between
point 110 and
point 112) may not break away from the wall or slip along it. Before the
condition of net
vapor generation (point 112), bubbles may leave the wall and may condense in
the flow of
subcooled liquid. After this point, an ever increasing quantity of vapor
accumulates in the
flow core.
[0081] In the neighborhood of point 114, the fraction of the channel
cross section
occupied by vapor is relatively large, and annular flow arises with the liquid
film flowing on
the channel wall and a vapor core occupying in the center. Within this regime
nucleate
boiling is suppressed (point 116). As the vapor-liquid mixture continues to
flow, the quantity
of liquid on the wall decreases and, at a certain boundary vapor quality
(point 118), dry out
occurs. In other words, at point 118 there may no longer be any liquid-to-heat-
transfer-
surface contact, and the wall temperature may rise. A transition occurs to
dispersed, or the
fog-type, flow of the mixture between point 118 and 120 with a maximum
occurring at point
122. After point 120, the entire flow stream is vaporized, and the steam is
superheated by
ordinary convective heat transfer.
[0082] As will be appreciated by those skilled in the art having
benefited from the
teachings of the present disclosure, while points 106-120 generally indicate
various
instances within a simplified mechanism of heat transfer, steam generation
mechanisms
are complex and often occur in concert. Accordingly, more quantitative
analyses may be
required to differentiate the mechanism(s) of heat transfer for a given system
(such as set
out herein with respect to EQN. 1 ¨ EQN. 6).
29
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A8141946CA
[0083] FIG. 2 provides a schematic of a system for generating steam
for a thermal
recovery process for hydrocarbon production in accordance with select
embodiments of the
present disclosure. In the system of FIG. 2, a steam generator 200 comprises a
pressurizing element 202, an economizer section 204, an eductor 206, a radiant
section
208, and a separator 210. The pressurizing element 202 is configured to
pressurize a
feedwater stream 212. After pressurization, the feedwater stream 212 enters
the
economizer section 204 which is configured to pre-heat the feedwater stream
212 (such as
by heat exchange with exhausted boiler gases). Because of the elevated
pressure of the
feedwater stream 212 in the economizer section 204, the feedwater stream 212
is not
substantially vaporized at this point. Instead, in select embodiments, the
feedwater stream
212 remains substantially or entirely in the liquid phase in the economizer
section 204. After
pre-heating in the economizer section 204, the feedwater stream 212 passes
through the
eductor 206. Within the eductor 206, the feedwater stream 212 acts as a motive
fluid in that
it draws an auxiliary-vapour stream 214 into the eductor 206 to mix with
feedwater stream
212 thereby forming a vapour-enhanced stream 216 (in which the vapour may for
example
be steam or another gas). As such, the eductor functions as a stream
connector. The
addition of the auxiliary-vapour stream 214 to the feedwater stream 212 is
carried out so
that that steam quality of the vapour-enhanced stream 216 is sufficient to
mitigate nucleate
boiling during heating in the radiant section 208. The eductor may also reduce
the pressure
of the feedwater stream 212 such that at least a portion of the feedwater
stream 212 is
vaporized to steam. The pressure drop at the eductor 206 is lower than would
be required
to attain the desired steam quality absent the addition of the auxiliary-
vapour stream 214.
In the radiant section 208, the vapour-enhanced stream 216 is heated to
generate steam
of a specified quality. The separator 210 is configured to separate a high-
quality steam
stream 218 from a low-quality steam stream 220. The high-quality steam stream
218 is
suitable for injection downhole in a thermal recovery process such as a SAGD
process. A
first portion of the high-quality steam stream 218 is recycled back to the
eductor 206 as the
auxiliary-vapour stream 214 (such that the auxiliary-vapour stream is a
recycled-steam
stream). A second portion of the high-quality steam stream 218 is supplied to
the thermal
recovery operation. The low-quality steam stream 220 contains the majority of
the
unvaporized/condensate water from the feedwater stream 212, and it may be
recycled into
the feedwater stream 212 (for example upstream of the pressurizing element
202) or
discharged from the steam generator 200.
Date Recue/Date Received 2020-05-13
A8141946CA
[0084] FIG. 3A provides a schematic of an eductor 300 which may be
utilized in
accordance with select embodiments of the present disclosure. The eductor
comprises a
motive-fluid inlet 302, a suction inlet 304, a nozzle 306, a diffuser 308, and
an outlet 310.
With reference to the schematic of FIG. 2, the eductor 300 may be configured
such that the
motive-fluid inlet 302 receives the feedwater stream 212, the suction inlet
304 receives the
auxiliary-vapour stream 214, and the outlet 310 discharges the steam-enhanced
stream
216.
[0085] A thermodynamic balance around the educator 300 may be
performed to
estimate its ideal performance. Ideal performance for compressors generally
assume a
reversible process (i.e. there is no change in entropy) and the shaft work put
into the fluid
acts on the fluid isentropically. For jet compressors (such as the eductor
300), there is no
shaft work, and the device can be assumed to be adiabatic (i.e. there is no
change in overall
enthalpy as the heat loss can be ignored). The specific enthalpy and entropy
for water and
steam is known for the normal range of operating conditions. In the present
example, the
pressures and temperatures are known for the feedwater stream 212 and the
auxiliary-
vapour stream 214. The ideal operating pressure at outlet 310 and the flowrate
of stream
212 into the motive-fluid inlet 302 are also known. As such, in the present
example, the
sole unknown variable is the flowrate of the auxiliary-vapour stream 214 into
the suction
inlet 304. By modeling a series of flow rates for auxiliary-vapour stream 214,
the resulting
discharge steam quality can be attained from the enthalpy balance. Knowing the
discharge
enthalpy, the discharge entropy is also known, and the recycle stream rate can
be adjusted
to balance the overall entropy. The theoretical recycle steam rate can be
determined for a
multitude of motive fluid conditions, and outlet pressures, and the real rate
will be some
fraction of the ideal rate.
[0086] By way of example, for a 325 C target jet pump discharge, and a 310
C
steam saturation recycle supply, estimated ideal discharge parameters from the
eductor
300 (discharge pressures and degrees of subcool) are shown in FIG. 3B, and the
related
quantity of the auxiliary-vapour stream, relative to the feedwater stream
inlet flow rate is
shown in FIG 3C. In FIG. 3B, reference numbers 320, 322, 324, 326, 328, 330,
332, 334,
336, and 338, indicate trends for 0 C, 5 C, 10 C, 15 C, 20 C, 25 C, 30
C,
C, 40 C, and 45 C subcool, respectively. In FIG. 3C, reference numbers 350,
352,
354, 356, 358, 360, 362, 364, 366, and 368, indicate trends for 0 C, 5 C, 10
C, 15 C, 20
C, 25 C, 30 C, 35 C, 40 C, and 45 C subcool, respectively.
31
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[0087] As will be appreciated by those skilled in the art having
benefited from the
teachings of the present disclosure, flash steam generation across a pressure
drop at the
eductor 300 reduces the quantity of auxiliary-vapour required to provide a
particular steam
quality for the vapour-enhanced stream. In the absence of any contribution
from the
auxiliary-vapour stream, the quantity of (simple) flash steam created by
reducing the
feedwater stream pressure to the steam-enhanced stream is shown in FIG 3D. In
FIG. 3D,
reference numbers 380, 382, 384, 386, 388, 390, and 392 indicate trends for 0
C, 5 C,
C, 15 C, 20 C, 25 C, and 30 C subcool, respectively.
[0088] As indicated in FIG. 3D, In the present example, operating the
feedwater
10 stream inlet at 16 MPa and 20 C subcool, provides a steam quality of
about 0.41 % steam
quality under simple flash conditions (to the eductor discharge conditions at
outlet 310). At
100 % efficiency, the eductor 300 draws in approximately 16.6 tonne of 310 C
auxiliary-
vapour stream per 100 tonne of feedwater stream, and discharges the enhanced-
steam
stream at 15 % steam quality at 325 C saturation temperature. In the present
example a
60 % efficiency rating for the eductor 300 equates to approximately 10 tonne
of 310 C
saturated steam per 100 tonne of feedwater stream being drawn in, resulting in
a discharge
of 9.8 % steam quality at 325 C saturation temperature.
[0089] In the present example, a higher motive inlet pressure is
needed to increase
the steam quality at the discharge condition. Operating at 17 MPa and 25 C
subcool,
equates to approximately 0.17% steam quality generated by the simple flash to
the eductor
discharge conditions. At 100 % jet pump efficiency, the eductor draws in
approximately
20.7 tonne of 310 C saturated steam per 100 tonne of feedwater, and
discharges 17.9 %
steam quality at 325 C saturation temperature. Assuming that a 60 %
efficiency is
maintained, approximately 12.4 tonne of 310 C saturated steam per 100 tonne
of
feedwater would be drawn in, resulting in a discharge of 11.6 % steam quality
at 325 C
saturation temperature.
[0090] Operating with less subcool in advance of the eductor 300 may
be beneficial,
as the resulting flash steam reduces the amount of auxiliary steam needed to
attain a target
discharge steam quality. For the above examples, operating with 10 C less
subcool (i.e.
10 C and 15 C subcool for 16 MPa and 17 MPa, respectively), results in a
discharge
steam quality (with 60 % eductor efficiency) of 16.2 % steam quality and 17.7
% steam
quality (from 9.8% and 11.6%). The simple flash from the eductor outlet
conditions results
in 6.21 % and 5.84% steam quality, respectively (from 0.41% and 0.17%).
32
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[0091] Conversely, operating with more subcool in advance of the
eductor is not
ideal, as auxiliary steam is required to provide heat to the motive fluid. For
the above two
examples, operating with 10 C more subcool (i.e. 30 C and 35 C subcool for
16 MPa
and 17 MPa respectively), results in a discharge steam quality (with 60%
eductor efficiency)
of 5.4% steam quality and 7.4% steam quality (from 9.8 % and 11.6%). The
simple flash
from the eductor outlet conditions results in 8.8 C and 9.1 C subcool,
respectively (from
0.41 % and 0.17% steam quality.
[0092] FIG. 4 provides a plot 400 of heat flux at the onset of
nucleate boiling (ONB)
as a function of the difference between the local fluid temperature and the
local saturation
temperature (i.e. the degree of subcool) for a series of different saturation
temperatures
and fluid flow rates as set out in Table 1 (functions 402, 404, 406, 408, and
410). Such
functions provide a means to determine the conditions associated with the
onset of nucleate
boiling for a given set of conditions. The plot 400 in FIG. 4 is based on a
steam generation
rate of about 167 T/hr from a six-coil steam generation unit (nominal pipe
size = 3";
schedule 80), where each coil provides a flow of about 27,833 kg/hr. The steam
generator
comprises a pressurizing element, an economizer section, an eductor, a radiant
section,
and a separator as shown schematically in FIG. 2. The eductor is configured
substantially
as shown schematically in FIG. 3.
[0093] Table 1: Saturation temperatures and flow rates for a series
of functions as
shown in plot 400 of FIG. 4
Reference number Saturation temperature Fluid flow rate
( C) (0/0)
402 360 100
404 340 100
406 320 100
408 100 100
410 100 10
33
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[0094] For each of the functions 402, 404, 406, 408, and 410, heat
flux values were
calculated using the film properties of the water (i.e. the arithmetic average
of the fluid and
the inside heat transfer surface temperature), the Dittus-Boelter formula and
the
temperature difference between the bulk fluid temperature and the temperature
at the
inside of the heat transfer surface.
[0095] Similarly, for each of the functions 402, 404, 406, 408, and
410 the nucleate
boiling heat transfer coefficient (at the onset of nucleate boiling) was
estimated using the
Burgles-Rohsenow nucleation criteria. Functions 402, 404, 406, 408, and 410
are
archetypal, and those skilled in the art having benefitted from the teachings
of the present
disclosure will appreciate how to generate alternative functions to account
for the specific
conditions associated with a particular steam generation system.
[0096] The plot 400 in FIG. 4 indicates that greater extents of
subcooling are
required to prevent nucleate boiling at increasing heat flux rates. Put
another way, for a
given heat flux, more subcool is needed as the saturation temperature (and the
coincident
operating pressure) is reduced. The plot in FIG. 4 also indicates that
significantly more
subcool is needed at low flow rates (see, for example, function 408 vs.
function 410).
[0097] Using the function 406 as an example, for a boiler providing a
peak heat flux
of 300,000 Winn' the plot of FIG. 4 indicates that the onset of nucleate
boiling occurs at
about 20 C. Accordingly, in the first stage of the steam generation method,
operational
parameters may be set to ensure the subcool is greater than about 22 C such
that the heat
flux is not sufficient to induce nucleate boiling.
[0098] FIG. 5 provides a plot 500 of heat flux as a function steam
quality at the
transition out of the nucleate boiling regime for a series of different
saturation temperatures
and fluid flow rates as set out in Table 2 (functions 502, 504, and 506). Such
functions
provide a means to determine the steam quality required to ensure that the
heat transfer
mechanism in the radiant-heating section of the steam generator is
predominantly forced
convective evaporation rather than saturated nucleate boiling.
34
Date Recue/Date Received 2020-05-13
A8141946CA
[0099] Table 2: Saturation temperatures and flow rates for a series
of functions as
shown in plot 500 of FIG. 5
Reference number Saturation temperature Fluid flow rate
( C) (0/0)
502 310 100
504 320 100
506 320 80
[00100] The plot 500 in FIG. 5 indicates that higher steam quality is
needed at higher
heat flux to ensure that heating is predominantly by the forced convective
evaporative
mechanism and not occurring with the saturated nucleate boiling mechanism. The
plot 500
in FIG. 5 also indicates that at lower pressures (for a given heat flux) less
steam quality is
needed to ensure that heating is predominantly by the forced convective
evaporative
mechanism and not by the saturated nucleate boiling mechanism (see, for
example,
function 502 vs. function 504). The plot in FIG. 5 also indicates that at
lower flow rates (for
a given heat flux) more steam quality is needed to ensure that heating is
predominantly by
the forced convective evaporative mechanism and not by the saturated nucleate
boiling
mechanism (see, for example, function 504 vs. function 506).
[00101] Using the function 504 as an example and assuming a peak heat
flux of
about 160,000 W/m2 in the radiant-heating section, the plot of FIG. 5
indicates that a steam
quality of at least about 12 % steam quality is necessary to ensure is that
heat transfer is
predominantly by the forced convective evaporative mechanism and not by the
saturated
nucleate boiling mechanism. . This finding, in combination with that from the
first stage,
suggests that a suitable system/method for generating steam in accordance with
the
present disclosure may comprise configuring the operational parameters of the
first stage
to ensure a subcool of at least about 22 C and configuring the operational
parameters of
the second stage to ensure a steam quality of at least about 12 %. Based on
these
parameters, an ideal system/method may be designed (Le. a 100 % efficient
system/method) by balancing the thermodynamic aspects of the eductor using an
isentropic
and isenthalpic analysis. For example, performing calculations based on a
discharge
pressure of 11,000 kPa (which may drop to about 9,800 kPa) due to hydraulic
loss up to
Date Recue/Date Received 2020-05-13
A8141946CA
the separator) and an auxiliary-vapour stream having a saturation temperature
of about
310 C, varying the saturation temperature and subcool of the motive fluid
(Le. the
feedwater stream) provides the results set out in Table 3.
[00102] Table 3: Operational parameters for a steam generation system
based on
an isentropic and isenthalpic analysis of an eductor having 100% efficiency
Entry Saturation Saturation Subcoo Steam Weight Outlet
pressure temp. I quality percent steam
(kPa) ( C) ( C) without recycled qualit
enhancemen steam in the Y
t from steam (0/0)
auxiliary enhanced
steam stream
stream (0/0)
(0/0)
1 12,762 330.0 0 5.72 35.83 40.17
2 12,762 330.0 5 2.94 11.74 14.56
3 12,762 330.0 10 0.33 10.98 11.47
4 12,762 330.0 15 4.27 11.22 9.50
5 12,762 330.0 20 9.19* 12.38 8.61
6 12,762 330.0 25 14.12* 14.35 8.73
7 12,762 330.0 30 19.06* 17.00 9.74
8 12,762 330.0 35 24.00* 20.18 11.51
9 14,504 340.0 0 11.21 27.05 35.73
14,504 340.0 5 8.10 23.93 30.54
11 14,504 340.0 10 5.25 21.65 26.17
12 14,504 340.0 15 2.57 20.22 22.65
13 14,504 340.0 20 0.03 19.61 20.00
14 14,504 340.0 25 4.76* 19.80 18.24
14,504 340.0 30 9.60* 20.73 17.35
16 14,504 340.0 35 14.47* 22.33 17.27
17 15,444 345.0 0 14.17 33.70 43.73
18 15,444 345.0 5 10.82 30.17 38.29
19 15,444 345.0 10 7.81 27.42 33.60
15,444 345.0 15 5.02 25.40 29.62
21 15,444 345.0 20 2.39 24.12 26.39
22 15,444 345.0 25 0.23 23.58 23.99
23 15,444 345.0 30 5.00* 23.75 22.27
24 15,444 345.0 35 9.81* 24.59 21.38
16,433 350.0 0 17.33 40.13 51.26
26 16,433 350.0 5 13.65 36.29 45.67
27 16,433 350.0 10 10.44 33.20 40.80
28 16,433 350.0 15 7.52 30.76 36.55
29 16,433 350.0 20 4.80 28.97 32.92
36
Date Recue/Date Received 2020-05-13
A8141946CA
30 16,433 350.0 25 2.21 27.83 29.95
31 16,433 350.0 30 0.51 27.35 27.67
32 16,433 350.0 35 5.24* 27.50 26.09
33 17,474 355.0 0 20.75 46.26 58.28
34 17,474 355.0 5 16.61 42.16 52.56
35 17,474 355.0 10 13.16 38.84 47.62
36 17,474 355.0 15 10.09 36.12 43.24
37 17,474 355.0 20 7.25 33.95 39.38
38 17,474 355.0 25 4.58 32.36 36.06
39 17,474 355.0 30 2.03 31.34 33.33
40 17,474 355.0 35 0.79 31.34 31.65
41 18,570 360.0 0 24.57 52.11 64.86
42 18,570 360.0 5 19.73 47.67 58.89
43 18,570 360.0 10 15.98 47.67 56.93
44 18,570 360.0 15 12.72 41.34 49.58
45 18,570 360.0 20 9.75 38.93 45.62
46 18,570 360.0 25 6.98 37.01 42.10
47 18,570 360.0 30 4.36 35.59 39.06
48 18,570 360.0 35 0.02 34.68 36.55
Note: * indicates that the outlet is liquid phase only. Values are the degrees
of subcool in C.
[00103] In Table 3, entry 13 indicates that the 20 C subcool required
to prevent
nucleate boiling in the first stage provides a steam quality of only 0.03 %
which is at least
about 11.7 % below that required to prevent nucleate boiling in the second
stage. However,
under the conditions of entry 13, the auxiliary-vapour stream provides an
additional 19.61
% to the steam quality. This enhancement to the steam quality at the second
stage ensures
the steam quality is sufficient to mitigate nucleate boiling in the radiative-
heating section of
the steam generator.
[00104] More generally, those skilled in the art having benefited from
the teachings
of the present disclosure will recognize that that high pressures are needed
to maintain the
system in the preferred operating range in the absence of the auxiliary-vapour
stream in
the present context and under the majority of typical operating conditions
employed in the
field. For example at 18,570 kPa and 20 C subcool, flashing in the absence of
the
enhancement from the auxiliary-vapour stream produces a steam quality of only
about
9.75% (entry 45 of Table 3). By adding heat via the auxiliary-vapour stream,
the methods
and systems of the present disclosure address this shortcoming and provide
improved
operational efficiency with systems and methods that are readily employable
under the
typical operating conditions employed in the field.
37
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[00105] As noted above, finned tubes may be configured to facilitate
the methods of
the present disclosure. FIG. 6 shows a scatter plot of typical normal peak
operating heat
flux values based on the external surface area throughout a typical boiler or
HRSG. In FIG.
6, reference numbers 600, 602, and 604 identify 9-path, 12-path, and 16-path
configurations, respectively. By selecting different finned configurations,
the resulting peak
heat flux (based on inside area) can be estimated as shown in FIG. 7 which
provides a
scatter plot of peak heat flux values on an inside area basis. In FIG. 7, 9-
path, 12-path, and
16-path configurations are plotted. For example, a flue gas temperature
between about 900
C and about 1000 C, correlates to a heat flux is of between about 25 kW/m2 to
30 kW/m2
of external surface area. Fins may be selected to effectively concentrate the
heat flux at
the external surface to the internal surface, where the boiling takes place,
by a multiplier as
exemplified in Table 4.
[00106] Table 4: Operational parameters and fin configurations for
considering
external and internal heat flux
Fin Height ins - 0.375 0.500 0.625 0.750 1.000
Fin spacing qty/inch - 5.000 5.000 5.000 5.000 5.000
Ratio (total outside area to pipe inside area, NPS 3 S160) Ao/Ai 133
6.96 9.07 1130 13.65 18.71
Ratio (total outside area to pipe inside area, NPS 3S80) Ao/Ai 1.21 6.30
8.21 10.23 1235 16.93
[00107] In the present example, a fin height of 12.7 mm (1/2 inch) and
a fin density
(i.e. fin quantity per unit length) of 197 fins/meter (5 fins per inch) would
likely be suitable
in that it would yield a 9.07 external to internal area ratio for NPS 3 S160
pipe, thereby
resulting in a heat flux of between about 225 kW/m2 and about 275 kW/m2 based
on inside
surface area.
[00108] Those skilled in the art having benefit from the teaching of
the present
disclosure will recognize how to select the fin profile and density to
maximize the peak heat
flux within the allowable temperature limits of the selected fin and tubing
material thereby
minimizing the coil length. By selecting appropriate fin profiles throughout
the economizer,
the peak heat flux may be controlled to a level commensurate with the amount
of subcool
available (to prevent subcooled boiling) and with the available capacity of
the auxiliary-
vapour stream (to have sufficient velocity to ensure that forced convective
evaporation
mechanism dominates over the saturated nucleate boiling heat transfer
mechanism). In the
present example, the approximate peak heat flux based on internal area for
bare tubes may
be between about 30 kW/m2 and about 40 kW/m2, indicating that, with the wide
availability
of fin profiles and density, a peak heat flux between about 30 kW/m2 and about
275 kW/m2
38
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may be attained with a flue gas temperature of 900 C to 1000 C (a typical
flue gas
temperature leaving the shock tube section).
[00109] FIG. 8 shows a scatter plot of typical normal peak operating
heat flux values
based on the external surface area for radiant and shock tube components of
typical boiler
or HRSG. In FIG. 8, reference numbers 800, 802, 804, 806, 808, and 810
identify 9-path
shock, 12-path shock,16-path shock, 9-path radiant, 12-path radiant, and 16-
path radiant
configurations, respectively. FIG. 9 provides a scatter plot of peak heat flux
values for the
same configurations on an inside area basis. In FIG. 9, reference numbers 900,
902, 904,
906, 908, and 910 identify 9-path shock, 12-path shock,16-path shock, 9-path
radiant, 12-
path radiant, and 16-path radiant configurations, respectively. For the shock
tube and
radiant sections, there may be less flexibility in managing the peak heat
flux, as the bare
tube peak heat flux is relatively high. For example, as shown FIG. 8, 975 C
to 1300 C flue
gas temperatures correspond to between about 150 kW/m2 and about 290 kW/m2 due
to
the radiant contribution to the external heat transfer mechanism. As will be
appreciated by
those skilled in the art having benefited from the teachings of the present
disclosure, this
may limit the outlet kinetic energy to within a prescribed value. In the
present example, the
kinetic energy may be determined by the product of the density (in kg/m3 or
lb/ft3) and the
square of the velocity (in m/s or ft/s) and may be limited to a value of
approximately 4839
kg=m/s2 (35,000 ft=lb/s2). This may be determined at the outlet condition of
the coil, at the
intended steam quality (typically 85 %) and intended outlet operating
pressure. As the
typical steam generator is a continuous coil from inlet to outlet, this then
defines the mass
rate for the individual coil. Setting a normal design envelope of 70% to 110 %
of the
maximum recommended value, this corresponds to a mass flux rate between
about1317
kg/m2/s and about 2069 kg/m2/s for 10 MPa operation, and between about 895
kg/m2/s and
about 1407 kg/m2/s for 5 MPa operation. The amount of subcool necessary to
prevent the
onset of nucleate boiling is primarily a function of the mass flux rate, the
heat flux rate, the
operating pressure, and slightly influenced with the coil diameter. The
relationship for NPS
3 S160 pipe coil is shown in the FIG. 10 and FIG. 11.
[00110] In FIG. 10, reference numbers 1000, 1002, 1004, 1006, and
1008 represent
6 MPa, 9 MPa, 12 MPa, 15 MPa, and 18 MPa, respectively (at 2069 kg/m2/s). In
FIG. 11,
reference numbers 1100, 1102, 1104, 1106 and 1108 represent 6 MPa, 9 MPa, 12
MPa,
15 MPa, and 18 MPa, respectively (at 895 kg/m2/s). Specific parameters for a
selection of
operating points from FIG. 10 and FIG. 11 are provided in Table 5.
39
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[00111] Table 5: Specific parameters for a selection of operating
points from FIG. 10
and FIG. 11.
Fraction of design rate 110% 100% 70%
Mass Flux 2069 kg/m2/s 1881 kg/m2/s 895 kg/m2/s
Operating Pressure 18 MPa 6 MPa 18 MPa 6 MPa 18 MPa 6 MPa
Subcool req'd at 100 kW/m2 4.5 C 5.8 C 4.900 6.3 C 9.5 C
11.800
Subcool req'd at 200 kW/m2 9.6 C 11.900 10.500 12.900 20.400
24.1 C
Subcool req'd at 300 kW/m2 15.0 C 18.0 C 16.4 C 19.6 C
31.9 C 36.7 C
[00112] As noted above, the steam quality necessary to provide
sufficient superficial
velocity to ensure that the predominant heat transfer mechanism is forced
convective
evaporation is primarily a function of the mass flux rate, the heat flux rate,
and the operating
pressure. In the present example, this is shown in FIG. 12 and FIG. 13. In
FIG. 12, reference
numbers 1200, 1202, and 1204 represent 10 MPa 2069 kg/m2/s, 7.5 MPa 1752
kg/m2/s,
and 5 MPa 1407 kg/m2/s, respectively. In FIG. 13, reference numbers 1300,
1302, and
1304 represent 10 MPa 1317 kg/m2/s, 7.5 MPa 1114 kg/m2/s, and 5 MPa 895
kg/m2/s,
respectively. Table 6 provides bracketing ranges for some of the operating
conditions
characterized in FIG. 12 and FIG. 13.
[00113] Table 6: Bracketing ranges for some of the operating
conditions
characterized in FIG. 12 and FIG. 13
Fraction of design rate 110% 100% 70%
Operating Pressure 10 MPa 5 MPa 10 MPa 5 MPa 10 MPa 5 MPa
Mass Flux (kg/m2/s) 2069 1407 1881 1279 1317 895
SQ req'd at 100 kW/m2 5.7% 4.4% 6.3% 4.8% 9.1% 7.0%
SQ req'd at 200 kW/m2 11.5% 8.9% 12.6% 9.8% 17.7% 14.0%
SQ req'd at 300 kW/m2 17.0% 13.4% 18.5% 14.6% 25.2% 20.3%
[00114] Managing heat flux with judicious selection of the fin profile
and density, and
perhaps changing the routing of the BFW through the economizer, will reduce
the amount
of required operating subcool and the required steam quality (and the quantity
of recycled
steam). Maintaining a peak heat flux to less than 50 kW/m2, the required
operating subcool
can be as low as 3 C to 5 C and the required operating steam quality can be
as low as 3
% to 5%.
Approach 2: Utilizing a novel flow-path configuration in combination with a
pressure-
reducing element
Date Recue/Date Received 2020-05-13
A8141946CA
[00115] As set out above, in the absence of an auxiliary-vapour
stream,
incorporating a pressure-reducing element into a conventional flow path is ill
suited to
satisfying the tolerances associated with steam generation for hydrocarbon
recovery. In
contrast, the present approach achieves similar results to those set out above
with respect
to the auxiliary-vapour-stream approach, by combining a novel flow-path
configuration with
a pressure-reducing element.
[00116] Briefly stated, the novel flow-path is configured to attenuate
the first-stage
heat flux into the feedwater stream as it approaches the pressure-reducing
element and,
provided the relevant parameters are selected judiciously, this provides
sufficient margins
at the pressure-reducing element for substantially avoiding the nucleate
boiling regime as
part of the feedwater water stream is flashed to steam. As the feedwater
stream
approaches the pressure-reducing element, attenuating the heat flux reduces
the subcool
required to stay below the onset of nucleate boiling and thus increases the
upper
temperature limit of the feed-water stream at the inlet to the pressure-
reducing element.
Higher feedwater-temperatures at the inlet to the pressure-reducing element
correlate to
higher steam qualities at the outlet of the pressure-reducing element, and the
parameters
can be configured to ensure that the steam quality at the outlet of the
pressure-reducing
device is above the threshold required to achieve evaporative heat transfer.
[00117] As set out below, attenuating the first-stage heat flux into
the feedwater
stream as it approaches the pressure-reducing element can be achieved by
configuring the
flow path of the feedwater stream to run co-current with the flow path of the
combustion
fluids of the steam generator. In conventional steam generators, the flow path
of the
feedwater stream runs counter-current to that of the combustion fluids such
that the
feedwater stream is exposed to progressively higher heat flux as it approaches
(and moves
through) the nucleate boiling regime. Embodiments of the present disclosure
are more
strategic in that they manage the operating heat flux and amount of subcool as
they
approach the pressure-reducing element. In embodiments of the present
disclosure, the
flow path of the feedwater stream is configured to run co-current with flow
path of the
combustion gas such that the highest heat flux is applied to the feedwater
stream while it
is still substantially subcooled. This may serve to decrease the heating
capacity of the
combustion-gas stream and to increase the temperature of the feedwater stream.
The co-
current flow relationship thus decreases the temperature differential between
the feedwater
41
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A8141946CA
stream and the combustion-gas stream thereby attenuating the heat flux into
the feedwater
stream as it approaches the pressure-reducing element.
[00118] One general aspect includes a method of generating steam for
use in a
hydrocarbon production process, the method comprising: passing a feedwater
stream from
a first-stage inlet to a first-stage outlet along a first-stage flow path,
wherein along the first-
stage flow path: (i) the feedwater stream is pressurized to a first-stage
pressure, (ii) the
feedwater stream is heated to a first-stage temperature by a first-stage heat
flux, (iii) the
first-temperature is maintained below the saturation temperature of the
feedwater stream,
and (iv) the first-stage flow path is configured to attenuate the first-stage
heat flux as the
feedwater stream approaches the first-stage outlet. The method further
comprises passing
the feedwater stream from the first-stage outlet through a pressure-reducing
element to a
second-stage inlet, wherein the second-stage inlet has a second-stage pressure
that is
sufficiently lower than the first-stage pressure to convert the feedwater
stream into a flashed
stream. The method further comprises passing the flashed stream from the
second-stage
inlet to a second-stage outlet along a second-stage flow path, wherein: (i) at
the second-
stage inlet the flashed stream has a steam quality that exceeds a threshold
for mitigating
nucleate boiling along a heated surface of the second-stage flow path, and
(ii) the flashed
stream is heated along the second-stage flow path by a second-stage heat flux
to increase
the steam quality of the flashed stream. The method further comprises
injecting at least a
portion of the flashed stream into a hydrocarbon-containing reservoir as
injected steam to
facilitate the hydrocarbon production process.
[00119] One general aspect includes a system for generating steam for
a
hydrocarbon production process, the system comprising: (i) a radiant section,
(ii) an
economizer having a lower section that is proximal to the radiant section and
an upper
section that is proximal to the lower section, and (iii) a combustion-gas flow
path that passes
from the radiant section to the lower section of the economizer to the upper
section of the
economizer. The system further comprises a first-stage flow path for passing a
feedwater
stream through at least a portion of the steam generator from a first-stage
inlet to a first-
stage outlet, wherein along the first-stage flow path: (i) the feedwater
stream is pressurized
to a first-stage pressure by a pressurizing element, (ii) the feedwater stream
is heated to a
first-stage temperature by a first-stage heat flux, (iii) the first-
temperature is maintained
below the saturation temperature of the feedwater stream, and (iv) at least
part of the first-
stage flow path is co-current with the combustion-gas flow path as the
feedwater stream
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A8141946CA
approaches the first-stage outlet. The system further comprises a pressure-
reducing
element that connects the first-stage outlet to a second-stage inlet, wherein
the pressure-
reducing element is configured to reduce the first-stage pressure to a second-
stage
pressure that is sufficiently lower than the first-stage pressure to convert
the feedwater
stream into a flashed stream. The system further comprises a second-stage flow
path for
passing the flashed stream through at least a portion of the steam generator
from the
second-stage inlet to a second-stage outlet, wherein: (i) at the second-stage
inlet the
flashed stream has a steam quality that exceeds a threshold for mitigating
nucleate boiling
along a heated surface of the second-stage flow path, and (ii) the flashed
stream is heated
along the second-stage flow path by a second-stage heat flux to increase the
steam quality
of the flashed stream. The system further comprises a steam injection section
configured
to inject at least a portion of the flashed steam stream into a hydrocarbon-
containing
reservoir as injected steam at a controlled injected steam quality to
facilitate the
hydrocarbon production process.
[00120] In the context of the present disclosure, the first-stage inlet may
take any
suitable position along the first-stage flow path. In the context of the
present disclosure, the
first-stage inlet may comprise a device (such as a valve), or not. For example
the first-stage
inlet may comprise un-modified pipe. Likewise, the first-stage outlet may take
any suitable
position along the first-stage flow path and may or may not comprise a device.
For example,
the first-stage outlet may comprise un-modified pipe, such that the first-
stage flow path
passes into the pressure-reducing element without restriction. Selecting a
suitable positions
and configurations for the first-stage inlet and the first-stage outlet is
within the purview of
those skilled in the art having benefitted from the teachings of the present
disclosure.
[00121] In the context of the present disclosure, the first-stage flow
path may take
any suitable configuration and may pass through various components of a steam
generator
as exemplified herein.
[00122] In the context of the present disclosure, the first stage
pressure may vary
along the first-stage flow path, or not. In select embodiments of the present
disclosure, the
first-stage pressure may be set by the pressurizing element and may be
between: (i) about
10 MPa and about 15 MPa; (ii) about 15 MPa and about 18 MPa; and/or (iii)
about 18 MPa
and about 22 MPa. Selecting a suitable first-stage pressure is within the
purview of those
skilled in the art having benefitted from the teachings of the present
disclosure.
43
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A8141946CA
[00123] In the context of the present disclosure, the first-stage
temperature varies
along the first-stage flow path as the feedwater stream is heated. In select
embodiments of
the present disclosure, at the first-stage inlet, the first-stage temperature
may be between:
(i) about 50 C and about 90 C; (ii) about 90 C and about 150 C; and/or
(iii) about 150 C
and about 210 C. In select embodiments of the present disclosure, at the
first-stage outlet,
the first-stage temperature may be between: (i) about 305 C and about 335 C;
(ii) about
335 C and about 350 C; and/or (iii) about 350 C and about 370 C. Selecting
suitable
first-stage temperatures for the first-stage inlet and the first-stage outlet
is within the
purview of those skilled in the art having benefitted from the teachings of
the present
disclosure.
[00124] In the context of the present disclosure, the first-stage heat
varies along the
first-stage flow path as it passes through various components of the steam
generator. In
select embodiments of the present disclosure, as the first-stage flow path
passes through
the radiant section, the first-stage average heat flux may be between: (i)
about 40 kW/m2
and about 90 kW/m2; and/or (ii) about 50 kW/m2 and about 90 kW/m2, on an
inside area
basis. In select embodiments of the present disclosure, as the first-stage
flow path passes
through the shock row of the lower section of the economizer, the first-stage
average heat
flux in the lower section may be between: (i) about 65 kW/m2 and about 135
kW/m2; and/or
(ii) about 75 kW/m2 and about 120 kW/m2, on an inside basis. In select
embodiments of the
present disclosure, as the first-stage flow path passes through the fifth row
of the lower
section of the economizer, the first-stage average heat flux in the lower
section may be
between: (i) about 25 kW/m2 and about 75 kW/m2; and/or (ii) about 35 kW/m2 and
about 65
kW/m2, on an inside basis. In select embodiments of the present disclosure, as
the first-
stage flow path passes through the first finned row in the upper section of
the economizer,
the first-stage average heat flux in the upper section may be between: (i)
about 85 kW/m2
and about 220 kW/m2; and/or (ii) about 110 kW/m2 and about 200 kW/m2, on an
inside
basis. In select embodiments of the present disclosure, as the first-stage
flow path passes
through the last finned row in the upper section of the economizer, the first-
stage average
heat flux in the upper section may be between: (i) about 3 kW/m2 and about 12
kW/m2;
and/or (ii) about 2 kW/m2 and about 10 kW/m2, on an inside basis.. Selecting
suitable first-
stage heat flux values at the various sections of the steam generator is
within the purview
of those skilled in the art having benefitted from the teachings of the
present disclosure.
44
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[00125] In the context of the present disclosure, the pressure-
reducing element may
be a continuous valve (e.g. an automatic modulating valve or a manual valve),
a fixed-
orifice restriction, or the like. Selecting a pressure-reducing element is
within the purview
of those skilled in the art having benefitted from the teachings of the
present disclosure.
[00126] In the context of the present disclosure, a flashed stream is one
which has
passed through the pressure-reducing element, such that at least a portion of
the steam is
in the gas phase as characterized by a non-zero steam quality greater. In
select
embodiments of the present disclosure, at the second stage inlet, the flashed
stream may
have a steam quality of between: (i) about 3 % and about 10 %; (ii) about 10 %
and about
20 %; and/or (iii) about 20 % and about 30 %. In select embodiments of the
present
disclosure, at the second stage outlet, the flashed stream may have a steam
quality of
between: (i) about 60 % and about 75 %; (ii) about 75 % and about 85 %; and/or
(iii) about
85 % and about 97 %. Selecting a suitable steam quality at the second-stage
inlet and the
second-stage outlet is within the purview of those skilled in the art having
benefitted from
the teachings of the present disclosure.
[00127] In the context of the present disclosure, the second-stage
inlet may take any
suitable position along the second-stage flow path. In the context of the
present disclosure,
the second-stage inlet may or may not comprise a device. For example the
second-stage
inlet may comprise un-modified pipe such that the second-stage flow path
passes from the
pressure-reducing element without restriction. Likewise, the second-stage
outlet may take
any suitable position along the second-stage flow path and may or may not
comprise a
device. For example, the second-stage outlet may comprise un-modified pipe,
such that
the second-stage flow path passes into a separator without restriction.
Selecting a suitable
positions and configurations for the second-stage inlet and the second-stage
outlet is within
the purview of those skilled in the art having benefitted from the teachings
of the present
disclosure.
[00128] In the context of the present disclosure, the second-stage
flow path may
take any suitable configuration and may pass through various components of a
steam
generator as exemplified herein.
[00129] In the context of the present disclosure, the second-stage heat
flux varies
along the second-stage flow path. In select embodiments of the present
disclosure, as the
first-stage flow path passes through the radiant section, the second-stage
average heat
Date Recue/Date Received 2020-05-13
A8141946CA
flux may be between: (i) about 40 kW/m2 and about 80 kW/m2; (ii) about 80
kW/m2 and
about 130 kW/m2; and/or (iii) about 130 kW/m2 and about 180 kW/m2, on an
inside area
basis. Selecting suitable second-stage heat flux values is within the purview
of those skilled
in the art having benefitted from the teachings of the present disclosure.
[00130] FIG. 14 shows a schematic of a system of generating steam in
accordance
with an embodiment of the present disclosure. The system comprises a steam
generator
1400 that has a radiant section 1402 and an economizer 1404. The economizer
1404 has
a lower section 1404a that is proximal to the radiant section 1402 and an
upper section
1404b that is proximal to the lower section 1404a. The area connecting the
radiant section
1402 and the lower section 1404a of the economizer 1404 may be referred to as
the "hog
trough".
[00131] The steam generator 1400 has a combustion-gas flow path that
is generally
identified with block arrows in FIG. 14. The combustion-gas flow path starts
with air/fuel
inlets, passes from the radiant section 1402 to the lower section 1404a of the
economizer
1404 to the upper section 1404b of the economizer 1404, and exits from an
exhaust (not
shown). The temperature of the combustion gases generally decreases along the
combustion-gas flow path as they dissipate heat as discussed below.
[00132] The steam generator 1400 has a first-stage flow path 1406 for
passing a
feedwater stream 1408 from a first-stage inlet 1410 to a first-stage outlet
1412. The first-
stage flow path 1406 passes through the upper section 1404b of the economizer
1404
along a path that is counter-current to the combustion-fuel flow path. In this
portion of the
first-stage flow path 1406, the feedwater stream 1408 is "preheated" by heat
exchange from
the combustion gases.
[00133] The first-stage flow path 1406 then exits the upper section
1404b of the
economizer 1404 and enters the radiant section 1402. This flow path is
unconventional ¨ a
conventional flow path would enter the upper section 1404a of the economizer
1400. In the
present case, as the first-stage flow path 1406 enters the radiant section
1402 where it
serpentines several times longitudinally around the periphery thereof. During
this portion of
the first-stage flow path 1406, the heat flux into the feedwater stream 1408
is relatively high
as the temperature differential between the combustion gases and the feedwater
stream
1408 is relatively large. However, at this point the feedwater stream 1408
still has significant
subcool, such that the relatively high heat flux is not sufficient to induce
nucleate boiling.
46
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Importantly, the first-stage flow path 1406 passing through the radiant
section 1402 results
leads to substantial heat transfer, and this lessens the temperature
differential between the
combustion-gas stream and the feedwater stream 1408. For example, the
temperature of
the combustion-gas stream in the hog trough of the steam generator 1400 may be
about
100 C lower than that in an analogous steam generator with a conventional
flow path.
[00134] The first-stage flow path 1406 then enters the lower section
1404a of the
economizer 1404 at the bottom and serpentines towards the top of the lower
section 1404a.
This creates a co-current flow relationship between the first-stage flow path
1406 and the
combustion-gas flow path through the lower section 1404a of the economizer
1404. The
heat flux into the feedwater stream 1408 is attenuated by the co-current flow
relationship.
The combustion-gas temperature of the lower section 1404a of the economizer
1400 is
substantially lower than that of the radiant section 1402 (and the temperature
of the
feedwater stream 1408 continues to increase), such that the heat flux into the
feedwater
stream 1408 during this portion of the first-stage flow path 1406 is further
attenuated. This
is important as the feedwater stream 1408 continues to approach the onset of
nucleate
boiling in this portion of the first-stage flow path 1406. As discussed in
detail below,
attenuating the heat flux into the feedwater stream 1408 allows for a higher
feedwater-
stream temperature without reaching the onset of nucleate boiling, because the
minimum
subcool required to prevent nucleate boiling is a function of heat flux.
[00135] The first-stage flow path 1406 ends at the first-stage outlet 1412.
A pressure-
reducing element 1414 links the first-stage outlet 1412 to a second-stage
inlet 1416. The
pressure-reducing element 1414 is configured to reduce the first-stage
pressure to a
second-stage pressure that is sufficiently lower than the first-stage pressure
to convert the
feedwater stream 1408 into a flashed stream 1418 that has a steam quality that
exceeds a
threshold for mitigating nucleate boiling. In other words, at the second-stage
inlet 1416, the
flashed stream 1418 has high enough steam content to ensure that evaporative
heat
transfer is the dominant mechanism, such that the nucleate boiling regime is
substantially
avoided. For example, a flashed-stream steam quality of about 12 A) may be
obtained by
configuring the pressure-reducing element 1414 to reduce the first-stage
pressure from
between about 15 MPa and 20 MPa to a second-stage pressure of about 6 MPa to
about
10 MPa.
[00136] The flashed stream 1418 follows a second-stage flow path 1420
that runs
from the second-stage inlet 1416 to a second-stage outlet 1422. At least a
portion of the
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second-stage flow path 1420 passes through the radiant section 1402. As the
flashed
stream 1418 passes through the radiant section 1402, heat flux into the
flashed stream
1418 increases the steam quality of the flashed stream 1418. For example the
flashed
stream 1418 may have a steam quality of about 5% to about 20 % (or more) at
the second
stage inlet, and heat flux along the second-stage flow path 1420 may result in
the flashed
steam 1418 having a steam quality of about 80% at the second-stage outlet
1422.
[00137] The steam generator 1400 may include a number of additional
elements. As
a first example, the steam generator may include a valve 1424 in the first-
stage flow path
1406 that bypasses a portion of the upper section 1404b of the economizer
1404. The valve
1424 may be configured to selectively allow a portion of the feedwater stream
1408 to enter
the radiant section 1402 without preheating. As such the valve 1424 may be
used to
modulate the temperature of the feedwater stream 1408 at the first-stage
outlet 1412 to
obtain the desired subcool and thus maintain a temperature below the onset of
nucleate
boiling. Accordingly, the valve 1424 may also be used to modulate the steam
quality of the
flashed stream at the second-stage inlet 1416.
[00138] As a second example, the steam generator 1400 may include a
separator
1424 that is configured to separate the flashed stream 1418 into a
substantially vapor-
phase stream 1426 and a substantially liquid-phase stream 1428. The
substantially-vapor-
phase stream 1426 may be injected into a hydrocarbon-containing reservoir to
facilitate a
hydrocarbon production process, and the substantially liquid-phase stream 1428
may be
recycled or discarded as blowdown waste.
[00139] As a third example, the steam generator 1400 may include a
valve 1430
between the stage-two outlet 1422 and the separator 1424. The valve 1430 may
be
configured to control the dynamic pressure of the flashed steam. Opening the
valve 1430
may reduce backpressure such that the dynamic pressure rises. The valve 1430
may be
modulated to provide a target dynamic pressure of between about 10,000
lb/ft/eand about
20,000 lb/ft/s2, for example.
[00140] As noted above, heating a fluid stream above a threshold steam
quality may
result in dryout conditions (see FIG. 1, reference number 118). Like nucleate
boiling, dryout
conditions may be associated with steam generator fouling such that they
represent an
upper limit, below which the steam quality of a liquid/vapour stream should be
maintained.
Accordingly, steam generator parameters may be configured to increase steam
quality
48
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while remaining within lower and upper bounds to avoid nucleate boiling and
dryout,
respectively.
[00141] Dryout conditions may be estimated using, for example, EQN. 7-
10:
a 0.25 a 0.70
x 0.58exp [0.52 ¨ 0.235Wee17Frk).37 (
PL ((DNB EQN. 7
G2)E
WeG = ________________________________
PGa
EQN. 8
G2
FrG = _____________________________________
PG(PL-PG)gDE
EQN. 9
qDNB = 0.1314.5hfg(g(PL-PG)or"
EQN. 10
wherein:
x is the steam quality transition to dryout conditions (expressed in mass
fraction);
De is the hydraulic diameter (expressed in m);
FrG is the Froude Number (dimensionless);
g is the acceleration due to gravity (expressed in nn/s2);
q is the local heat flux (expressed in Whin2);
qDNB is the heat flux at departure from nucleate boiling (expressed in Whin2);
G is the mass flux (expressed in kg/m2/s);
hfy is the evaporative enthalpy (expressed in J/kg);
W eG is Weber Number (dimensionless);
PG is the vapour density (expressed in kg/m3);
PL is the liquid density (expressed in kg/m3); and
6 is the surface tension (expressed in N/nn).
[00142] Dryout conditions may be used as a limit for determining an
appropriate
flowrate for a feedwater stream and for determining an appropriate (dry) steam
generation
rate (having regard to the relevant parameters for the steam generator). For
example, FIG.
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15A and FIG. 15B show plots of feedwater stream flowrate as a function of
steam quality
at dryout based on a steam-injection temperature at about 310 C for two
common coils
(NPS 3 Sch 80 coil and NPS4 Sch 80 coil, respectively). In FIG. 15A and FIG.
15B, plots
for a series of heat flux values are identified by reference numbers as set
out in Table 7.
[00143] Table 7: Reference numbers and heat flux values (on an inside area
basis)
for the series of plots of FIG. 15A and FIG. 15B.
FIG. 15A FIG. 15B
Reference Number Heat Flux (kW/m2) Reference Number Heat Flux (kW/m2)
1502 42 1512 42
1504 58 1514 58
1506 74 1516 74
1508 90 1518 90
1510 106 1520 106
[00144] A typical boiler may operate at, for example, 74 kW/m2 (on an
inside area
basis). If the desired steam quality is about 80 % at the outlet of the
radiant section in the
second stage (and/or at the inlet to a separator), the plots 1506 and 1516
indicate maximum
feedwater flowrates of about 14,000 kg/hr and about 25,000 kg/hr, respectively
(as
indicated with dashed lines in each of FIG. 15A and FIG. 15B. At 82 % steam
quality, the
maximum feedwater flowrates are about 12,141 kg/hr and about 23,589 kg/hr, and
these
correlate to maximum dry steam generation rates of about 9,955 kg/hr and about
19,343
kg/hr. Accordingly, suitable parameters for obtaining about a 10,000 BPD dry
steam rate
may employ four parallel paths of NPS4 Sch80 coil, operating at 20,167 kg/hr
flow path and
82% steam quality at the outlet of the second-stage flow path (FIG. 15B).
[00145] The selected feedwater rate may then be used to determine the
minimum
steam quality required to surpass the nucleate boiling regime as the flashed
stream flows
from the second-stage inlet. For example, FIG. 16A and FIG. 16B show plots of
flowrate
Date Recue/Date Received 2020-05-13
A8141946CA
as a function of minimum steam quality for the same steam-injection
temperature (about
310 C) and for the same coil types (NPS 3 Sch 80 coil and NPS4 Sch 80 coil,
respectively).
In FIG. 16A and FIG. 16B, plots for a series of heat flux values are
identified by reference
numbers as set out in Table 8.
[00146] Table 8: Reference numbers and heat flux values (on an inside area
basis)
for the series of plots of FIG. 16A and FIG. 16B.
FIG. 16A FIG. 16B
Reference Number Heat Flux (kW/m2) Reference Number Heat Flux (kW/m2)
1602 42 1612 42
1604 58 1614 58
1606 74 1616 74
1608 90 1618 90
1610 106 1620 106
[00147] Using the same average heat flux (74 kW/m2), and coil
selection (NPS4 Sch
80) as above, the selected flow rate (23,589 kg/hr) correlates to minimum
steam quality at
.. the stage-two inlet of about 7.5% (as indicates with dashed lines in FIG.
16B).
[00148] The selected steam quality at the stage-two inlet may then be
used to
determine the required subcool at the first-stage outlet. For example, FIG.
17A ¨ FIG. 17D
show plots of steam quality at the second-stage inlet as a function of the
first-stage
pressure. FIGS. 17A, 17B, 17C, and 17D, correspond to injection pressures of
7.4 MPa,
8.6 MPa, 9.9 MPa, and 11.3 MPa, respectively. In FIG. 17A¨ FIG. 17D plots fora
series
of subcool values are identified by reference numbers as set out in Table 9.
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[00149] Table 9: Reference numbers and subcool values for the series of
plots of
FIG. 17A ¨ FIG. 17D.
FIG. 17A FIG. 17B
Reference Number Subcool ( C) Reference Number Subcool ( C)
1702 0.01 1712 0.01
1704 5 1714 5
1706 10 1716 10
1708 15 1718 15
1710 20 1720 20
FIG. 17C FIG. 17D
Reference Number Subcool ( C) Reference Number Subcool ( C)
1722 0.01 1732 0.01
1724 5 1734 5
1726 10 1736 10
1728 15 1738 15
1730 20 1740 20
[00150] For a desired second-stage pressure of about 10 MPa, FIG. 17C
provides
the relevant correlation. The minimum steam quality at the second-stage inlet
was
determined to be about 7.5 A). Targeting a steam quality of 15 A) at the
second-stage inlet
provides a generous margin and, at a typical second-stage pressure of about 18
MPa, the
required subcool at the first-stage outlet is about 15 C (as identified by
the dashed lines in
FIG. 17C.
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[00151] The required subcool is dependent on the first-stage heat
flux, the first-stage
pressure, the first-stage pipe diameter, and feedwater flow rate. In the
present case, the
first-stage pipe diameter may be set by the selection of NPS 3 Sch 160 coil,
the first stage
pressure may be set as discussed with reference to FIG. 17A¨ FIG. 17D, and the
feedwater
flow rate may be set as discussed with reference to FIG. 15A ¨ FIG. 15B. FIG
18A and
FIG. 18B, show plots of minimum subcool as a function of heat flux at first-
stage pressures
of 15 MPa and 20 MPa, respectively. In FIG. 18A¨ FIG. 18B, plots for a series
of feedwater
flow rates are identified by reference numbers as set out in Table 10.
[00152] Table 10: Reference numbers and feedwater flowrates for the
series of plots
of FIG. 18A and FIG. 18B.
FIG. 18A FIG. 18B
Reference Number Flow Rate (kg/h) Reference Number Flow Rate (kg/h)
1802 10,000 1808 10,000
1804 20,000 1810 20,000
1806 30,000 1812 30,000
[00153] As discussed above, the heat flux into the feedwater stream as
it
approaches the first-stage outlet can be attenuated by strategically
configuring the first-
stage flow path. By configuring the flow path (e.g. co-current flow with the
combustion gas
in the lower economizer section), and/or the amount of extended surface (e.g.
bare tubes
at the inlet of the lower economizer section), the operating heat flux at the
first-stage outlet
can be minimized. For example, the operating heat flux at the first-stage
outlet could be
managed to less than 60 kW/m2(on an inside area basis). At 60 kW/m2, 18 MPa,
and 20,000
kg/hr, the required subcool to be surpass the nucleate boiling region (and
enter the
convective heat transfer regime) is only about 3 C at 20 MPa, and it is only
about 4 C at
15 MPa. In the present case, if the operation is at 15 C subcool and 18 MPa,
the first stage
is operating within the convective heat transfer region with 12 C margin. If
10 C subcool
is achieved, the steam quality at the second-stage inlet will be about 17 %.
53
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[00154] Accordingly, by minimizing the required subcool, the steam
quality into the
second stage can be maximized for a given first-stage pressure. Alternatively,
the first-
stage pressure can be minimized for a given operating subcool.
[00155] Providing an excess of surface area in the upper section of
the economizer
(by selecting appropriate fin profiles and densities) provides additional
flexibility with
respect to the required subcool at the first-stage outlet. This is illustrated
in FIG.19, which
shows plots of heat flux across a set of economizer rows (1 = shock row) for a
series of
heat release profiles. In FIG. 19, the series of heat-release profiles are
identified by
reference numbers as set out in Table 11.
[00156] Table 11: Reference numbers and heat release profiles for the
series of plots
of FIG. 19.
Reference Number Heat Release (c/o) Reference Number Flow Rate (kg/h)
1902 100 1908 70
1904 90 1910 60
1906 80
[00157] Plotting the operating conditions of the OTSG, the dryout
conditions, the
required SQ to minimize saturated nucleate boiling, and the required subcool
to minimize
subcooled nucleate boiling, helps to identify the especially problematic areas
for scaling
when operating a steam generator with deoiled but otherwise untreated water.
FIG. 20
provides an archetypal plot in this respect for a conventional OTSG design.
[00158] In FIG. 20, the steam quality along the radiant section is
indicated by
reference number 2002, and the steam quality threshold for dryout is indicated
by reference
number 2004. The cross over between the two plots indicates that, for a
substantial portion
of the flow path, the conventional OTSG operates at a steam quality that
exceeds the dryout
threshold. This may lead to premature steam generator fouling.
[00159] In FIG. 20, the steam quality required to surpass the nucleate
boiling regime
is indicated by reference number 2006. The cross over between the plots 2002
and 2006
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two lines indicates that, for a substantial portion of the flow path, the
conventional OTSG
operates within the nucleate boiling regime. This may lead to premature steam
generator
fouling.
[00160] In FIG. 20, the subcool of the feedwater stream as it passes
through the
economizer is indicated by reference number 2008, and the required subcool to
remain
below the onset of nucleate boiling is indicated by reference number 2010. At
the inlet to
the economizer, the feedwater stream has the highest subcool, and this
diminishes as the
feedwater stream is heated (right to left on plot 2008). As the feedwater
stream approaches
the outlet of the economizer, the heat flux increases due to the increase in
the combustion-
gas temperature. At the same time, the required margin on subcool further
diminishes and
eventually there is less subcool available than is needed to prevent nucleate
boiling (plot
2008 crosses plot 2010). The crossover point indicates that the bulk boiling
temperature is
reached, and this may lead to premature steam generator fouling. Beyond this
point the
steam quality starts to increase as the flow path passes through the bottom of
the
economizer and enters into the radiant section. There is the least amount of
steam quality
margin in the shock row, and the sudden jump in required SQ is due to the
higher heat flux
in the shock row.
[00161] The foregoing analysis suggests that the expected problematic
areas are
the bottom of the economizer and the outlet of the radiant section, and this
is confirmed
with field observations of operating boilers. The flow paths utilized in
select embodiments
of the present disclosure may reduce these effects as illustrated in FIG. 21.
FIG. 21
provides archetypal plots that are analogous to those FIG. 20, but configured
in accordance
with an embodiment of the present disclosure. In the embodiment of FIG. 21,
the first-stage
flow path is routed through the radiant section to minimize the required
subcool to prevent
nucleate boiling. In the embodiment of FIG. 21, the first-stage inlet is at
the top of the upper
section of the economizer, such that heat exchange with the combustion-gas
stream occurs
counter-currently. To maximize heat transfer with the combustion-gas stream,
the upper
section of the economizer has finning on the exterior of the feedwater pipe
with different fin
heights. The largest fins (i.e. the high-fin sections) are in the upper
section of the
economizer. Once the feedwater stream leaves the upper section of the
economizer, it is
directed to the radiant section of the steam generator. Several lengths of
pipe in the radiant
section preheat the feedwater stream as it flows through the radiant section
in a serpentine
fashion. The feedwater stream is then directed to the lower section of the
economizer,
Date Recue/Date Received 2020-05-13
A8141946CA
where heat exchange occurs co-currently as both the feedwater stream and the
combustion
gas flow upwards through the economizer. This reduces the required amount of
subcool as
discussed above.
[00162] In the embodiment of FIG. 21, the steam quality at the second-
stage inlet is
increased by flashing through a valve. Flashing through a valve is an
adiabatic process,
and the enthalpy condition at the second-stage inlet is equal to the enthalpy
condition of
the outlet of the first stage. Since the desired enthalpy condition of the
first-stage outlet is
known, the enthalpy condition of at the second-stage inlet is known, and the
relative amount
of heat absorbed for each stage is known.
[00163] As noted above, introducing a pressure-reducing element into a
conventional OTSG flow path is likely to produce a steam quality at the inlet
to the radiant
section that is less than that required to surpass the nucleate boiling regime
(such as less
than 8% -- see, plots 2002 and 2006 in FIG. 20). Since a higher steam quality
is desirable
at the second-stage inlet, the embodiment of FIG. 21 captures heat from the
radiant section
in the first stage as set out above.
[00164] In the embodiment of FIG. 21bare tubes are used to minimize
the heat flux
as the feedwater stream approaches the pressure-reducing element (in this
case, a valve).
This provides a lower required subcool temperature (compared to the
conventional design)
and allows a higher first-stage outlet temperature for a given operating
margin. The higher
outlet temperature increases enthalpy ¨ and therefore the steam quality ¨ at
the second-
stage inlet.
[00165] In FIG. 21, the steam quality along the radiant section is
indicated by
reference number 2102. In FIG. 21, the steam quality threshold for dryout
under peak and
average heat flux conditions are indicated by reference numbers 2104a and
2104b,
respectively. Plot 2102 does not overlap with plot 2104a, which indicates that
the
embodiment of FIG. 21 can be configured to achieve the desired steam quality
at the
second-stage outlet without exceeding the dryout threshold under average heat
flux
conditions.
[00166] In FIG. 21, the steam quality required to surpass the nucleate
boiling regime
under peak and average heat flux conditions are indicated by reference numbers
2106a
and 2106b, respectively. Plot 2102 does not overlap with plot 2106a or 2106b,
which
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indicates that the embodiment of FIG. 21 can be configured to achieve the
required steam
quality to surpass the nucleate boiling regime after the feedwater stream is
flashed.
[00167] In FIG. 21, the subcool of the feedwater stream as it passes
through the
economizer is indicated by reference number 2108. In FIG. 21, the required
subcool to
remain below the onset of nucleate boiling under peak and average heat flux
conditions are
indicated by reference numbers 2110a and 2110b. Plot 2108 does not overlap
with plot
2110a or 2110b, which indicates that the embodiment of FIG. 21 can be
configured to
remain below the onset of nucleate boiling as the feedwater stream approaches
the first-
stage outlet. In FIG. 21, the starting position plot 2108 is determined by the
first-stage
pressure. Increasing the first-stage pressure increases the subcool for a
given operating
temperature. Increasing the first-stage pressure shifts plot 2108 upwards.
Concluding Remarks
[00168] It should be understood that, in the context of the present
disclosure, while
methods and systems 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 description and the claims, are defined herein to mean
"one or more
than one" of the element that it introduces.
[00169] 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.
57
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[00170] 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 in the
art having the benefit of the teachings of the present disclosure. 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
of the present disclosure. Moreover, 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.
58
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