U.S. patent application number 14/102767 was filed with the patent office on 2014-06-19 for liquid indirect steam boiler.
This patent application is currently assigned to CONOCOPHILLIPS COMPANY. The applicant listed for this patent is CONOCOPHILLIPS COMPANY. Invention is credited to Christopher R. COPELAND, David W. LARKIN, Richard D. SADOK, Peter N. SLATER.
Application Number | 20140166281 14/102767 |
Document ID | / |
Family ID | 50929601 |
Filed Date | 2014-06-19 |
United States Patent
Application |
20140166281 |
Kind Code |
A1 |
LARKIN; David W. ; et
al. |
June 19, 2014 |
LIQUID INDIRECT STEAM BOILER
Abstract
Systems and methods generate steam in hydrocarbon recovery
operations and may further enable emulsion separation and product
upgrading. The methods rely on indirect boiling of water by contact
with a thermal transfer liquid heated to a temperature sufficient
to vaporize the water. Examples of the liquid include oils,
recovered hydrocarbons, liquid metals and brine. Heating of the
liquid may utilize circulation of the liquid across or through a
furnace, heat exchangers, or a gas-liquid contactor supplied with
hot gas. Further, a solvent for bitumen introduced into the water
may also vaporize upon contact with the thermal transfer
liquid.
Inventors: |
LARKIN; David W.; (Tulsa,
OK) ; SLATER; Peter N.; (Bartlesville, OK) ;
COPELAND; Christopher R.; (Calgary, CA) ; SADOK;
Richard D.; (Bartlesville, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
CONOCOPHILLIPS COMPANY |
Houston |
TX |
US |
|
|
Assignee: |
CONOCOPHILLIPS COMPANY
Houston
TX
|
Family ID: |
50929601 |
Appl. No.: |
14/102767 |
Filed: |
December 11, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61737945 |
Dec 17, 2012 |
|
|
|
Current U.S.
Class: |
166/272.3 ;
166/57 |
Current CPC
Class: |
F22B 1/167 20130101;
E21B 43/2406 20130101 |
Class at
Publication: |
166/272.3 ;
166/57 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. A method of generating steam in a hydrocarbon recovery
operation, comprising: recovering a mixture of produced water and
hydrocarbons from an underground formation; introducing the water
into a vessel; contacting the water within the vessel with a liquid
heated to above a boiling point of the water for vaporization of
the water into steam within the vessel; separating the steam in an
overhead of the vessel from the liquid; and injecting the steam
into the formation to facilitate additional hydrocarbon
recovery.
2. The method according to claim 1, wherein the liquid is petroleum
based.
3. The method according to claim 1, wherein the liquid includes
brine.
4. The method according to claim 1, wherein the liquid is heated by
heating coils disposed in the liquid within the vessel.
5. The method according to claim 1, wherein the liquid is heated by
molten sodium circulated through heating coils disposed in the
liquid within the vessel.
6. The method according to claim 1, wherein the liquid is heated in
a circulation loop from the vessel by gas contact heat exchange
before being returned to the vessel.
7. The method according to claim 1, wherein the liquid is heated in
a circulation loop from the vessel by a furnace before being
returned to the vessel.
8. The method according to claim 1, wherein the water is
pressurized to at least 10,000 kilopascals prior to being
introduced into the vessel.
9. The method according to claim 1, wherein the water is separated
from the hydrocarbons prior to being introduced into the
vessel.
10. The method according to claim 1, further comprising preheating
the water prior to being introduced into the vessel.
11. The method according to claim 1, further comprising adding a
solvent to the water for vaporization of the solvent with the
water.
12. The method according to claim 1, wherein the water is separated
from the hydrocarbons at a facility separate and remote from
location of the vessel at a well pad where the steam is
injected.
13. A system for generating steam in a hydrocarbon recovery
operation, comprising: a production well for recovering a mixture
of produced water and hydrocarbons from an underground formation; a
vessel coupled to the production well for receiving the water; a
liquid disposed within the vessel in contact with the water and
heated to above a boiling point of the water for vaporization of
the water into steam within the vessel; and an injection well in
fluid communication with the steam separated in an overhead of the
vessel from the liquid and for conveying the steam into the
formation to facilitate additional hydrocarbon recovery.
14. The system according to claim 13, further comprising a nozzle
to introduce the water as droplets into the vessel.
15. The system according to claim 13, wherein the liquid is
petroleum based.
16. The system according to claim 13, wherein the liquid includes
brine.
17. The system according to claim 13, further comprising heating
coils disposed in the liquid within the vessel for transfer of heat
to the liquid.
18. The system according to claim 13, further comprising heating
coils disposed in the liquid within the vessel for transfer of heat
to the liquid from molten sodium circulated within the coils.
19. The system according to claim 13, further comprising a
circulation loop from the vessel for heating the liquid by heat
exchange in a gas-liquid contactor.
20. The system according to claim 13, further comprising a
circulation loop from the vessel for heating the liquid by a
furnace before being returned to the vessel.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional application which
claims benefit under 35 USC .sctn.119(e) to U.S. Provisional
Application Ser. No. 61/737,945 filed Dec. 17, 2012, entitled
"LIQUID INDIRECT STEAM BOILER," which is incorporated herein in its
entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] None.
FIELD OF THE INVENTION
[0003] Embodiments of the invention relate generally to methods and
systems for use in hydrocarbon recovery operations, such as oil
sands production.
BACKGROUND OF THE INVENTION
[0004] Several techniques utilized to recover hydrocarbons in the
form of bitumen from oil sands rely on generated steam to heat and
lower viscosity of the hydrocarbons when the steam is injected into
the oil sands. One common approach for this type of recovery
includes steam assisted gravity drainage (SAGD). The hydrocarbons
once heated become mobile enough for production along with the
condensed steam, which is then recovered and recycled.
[0005] Costs associated with building a complex, large,
sophisticated facility to process water and generate steam
contribute to economic challenges of oil sands production
operations. Such a facility represents much of the capital costs of
these operations. Chemical and energy usage of the facility along
with expense of diluents to maintain transportability of the
bitumen once cooled also contribute to operating costs.
[0006] Past approaches rely on once through steam generators
(OTSGs) to produce the steam. However, boiler feed water to these
steam generators requires expensive de-oiling and treatment to
limit boiler fouling problems. Even with this treatment, fouling
issues persist and are primarily dealt with through regular pigging
of the boilers. This recurring maintenance further increases
operating costs and results in a loss of steam production capacity,
which translates to an equivalent reduction in bitumen
extraction.
[0007] Therefore, a need exists for methods and systems for
generating steam and/or product upgrading that enable efficient
hydrocarbon recovery operations.
BRIEF SUMMARY OF THE DISCLOSURE
[0008] In one embodiment, a method of generating steam in a
hydrocarbon recovery operation includes recovering a mixture of
produced water and hydrocarbons from an underground formation. The
method further includes introducing the water into a vessel and
contacting the water within the vessel with a liquid heated to
above a boiling point of the water for vaporization of the water
into steam within the vessel. In addition, separating the steam in
an overhead of the vessel from the liquid permits injecting the
steam into the formation to facilitate additional hydrocarbon
recovery.
[0009] For one embodiment, a system for generating steam in a
hydrocarbon recovery operation includes a production well for
recovering a mixture of produced water and hydrocarbons from an
underground formation. The system further includes a vessel coupled
to the production well for receiving the water and a liquid
disposed within the vessel in contact with the water and heated to
above a boiling point of the water for vaporization of the water
into steam within the vessel. In addition, the system includes an
injection well in fluid communication with the steam separated in
an overhead of the vessel from the liquid and for conveying the
steam into the formation to facilitate additional hydrocarbon
recovery.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] A more complete understanding of the present invention and
benefits thereof may be acquired by referring to the follow
description taken in conjunction with the accompanying
drawings.
[0011] FIG. 1 is a schematic of a system in which produced water is
separated from recovered oil and vaporized by contact with a heated
liquid to produce steam for injection, according to one embodiment
of the invention.
[0012] FIG. 2 is a schematic of an alternative arrangement to
contact a mixture of water and oil with more of the oil that has
been heated to vaporize the water and result in visbreaking of the
oil, according to one embodiment of the invention.
[0013] FIG. 3 is a schematic of another system utilizing brine
heated by coils within a steam generation vessel to vaporize water
introduced into the vessel, according to one embodiment of the
invention.
[0014] FIG. 4 is a schematic of a system employing a gas-liquid
contactor to maintain temperature of a heated liquid used to
generate steam, according to one embodiment of the invention.
[0015] FIG. 5 is a schematic of a system having a condensable gas
circulated through a gas-liquid contactor employed to maintain
temperature of a heated liquid used to generate steam, according to
one embodiment of the invention.
DETAILED DESCRIPTION
[0016] Turning now to the detailed description of the preferred
arrangement or arrangements of the present invention, it should be
understood that the inventive features and concepts may be
manifested in other arrangements and that the scope of the
invention is not limited to the embodiments described or
illustrated. The scope of the invention is intended only to be
limited by the scope of the claims that follow.
[0017] Embodiments of the invention relate to systems and methods
of generating steam in hydrocarbon recovery operations and that may
further enable emulsion separation and product upgrading. The
methods rely on indirect boiling of water by contact with a thermal
transfer liquid heated to a temperature sufficient to vaporize the
water. Examples of the liquid include brine, liquid metals and
petroleum based fluids, such as oils, bitumen or recovered
hydrocarbons. Heating of the liquid may utilize circulation of the
liquid across or through a furnace, heat exchangers, or a
gas-liquid contactor supplied with hot gas. Further, a solvent for
bitumen introduced into the water may also vaporize upon contact
with the thermal transfer liquid.
[0018] FIG. 1 shows a steam generator vessel 100 for use in a
steam-assisted hydrocarbon recovery operation, which may utilize an
injection well 101 and a production well 102 in an underground
formation. Steam-assisted gravity drainage (SAGD) provides one
exemplary approach for recovering hydrocarbons even though steam
generation described herein may be used in other processes, such as
cyclic steam stimulation or steam flood. For the SAGD, the
injection well 101 includes a horizontal length extending parallel
and above the production well 102.
[0019] In operation, the production well 102 recovers an emulsion
or mixture 104 of hydrocarbons and produced water. A separator 106
and free-water knockout units 108 remove hydrocarbon product 110
from untreated water 112. The water 112 at time of being generated
into the steam may still contain: at least about 1000 parts per
million (ppm), at least 10,000 ppm or at least 45,000 ppm total
dissolved solids; at least 100 ppm, at least 500 ppm, at least 1000
ppm or at least 15,000 ppm organic compounds or organics; and at
least 1000 ppm free oil, thereby enabling sustainable recycle of
the water 112 without stringent treatment requirements of
conventional boiler feed.
[0020] For some embodiments, the water 112 mixes with a solvent 114
for bitumen prior to vaporization in the vessel 100. The solvent
114 thus may flow in liquid phase into the water 112. Vaporization
of the water 112 along with the solvent 114 within the vessel 100
results in solvent vapors also being introduced into the injection
well 101 as may be desired in some recovery operations.
[0021] The solvent 114 may include hydrocarbons having between 3
and 30 carbon atoms, such as butane, pentane, naphtha and diesel.
Temperatures associated with the indirect boiling described herein
limit potential problems from cracking these hydrocarbons, which
can tend to occur if passed through direct fired boilers that may
thus require injection of any wanted solvents into superheated
steam rather than boiler feed. Feed to the vessel 100 may include
between 5 and 30 percent of the solvent 114 by volume.
[0022] The solvent 114 may further provide an energy requirement
for vaporization that is at least 10 percent lower than water
alone. For example, a 28:72 ratio of butane to water reduces steam
generator duty using the vessel 100 by 24 percent as compared to
water alone. Further, vaporization of the solvent 114 in the vessel
100 eliminates need for superheated steam generation relied on when
the solvent 114 is added post steam generation.
[0023] A pump 116 pressurizes the water 112 for entry into the
vessel 100 maintained at a pressure of at least 10,000 kilopascals
to achieve a corresponding desired steam injection pressure. In
some embodiments, the pump 116 pressurizing the water 112 to above
13,500 kilopascals before the water 112 enters the vessel 100 at a
temperature below its boiling point at such pressure. A nozzle 118
or other dispersion inlet may introduce the water 112 into the
vessel 100 as droplets or dispersed flow to aid in heat transfer
between the water 112 and a thermal transfer liquid 120, which
vaporizes the water 112. The nozzle 118 may direct the water 112
toward the liquid 120 or be disposed within the liquid 120 as shown
in other figures.
[0024] Any fluid having a boiling point above the water 112 may
form the liquid 120, which may also not be miscible with the water
112. Examples of the liquid 120 include liquid metals, brine and
hydrocarbons, such as bitumen, light cycle oil, heavy cycle oil,
coker gas oil or aromatics. Using hydrocarbons that have already
been cracked as the liquid 120 may limit loss and fouling from
potential further cracking when the liquid 120 is intended to be
recycled within the vessel 100 whereas use of bitumen as the liquid
120 may provide potential for withdrawal of upgraded products.
[0025] In some embodiments, a circulation loop 122 through which
the liquid 120 from the bottom of the vessel 100 is pumped reheats
the liquid 120 cooled by heat transfer to the water 120. A heater
124 such as a furnace, heat exchanger, or gas-liquid contactor
supplied with a hot gas increases temperature of the liquid 120. In
some embodiments, the heater 124 increases temperature of the
liquid 120 to above 350.degree. C., 400.degree. C., 425.degree. C.
or 475.degree. C. before being returned to the vessel 100 thereby
maintaining temperature of the liquid 120 within the vessel 100
above a boiling point of the water (e.g., 315.degree. C.).
[0026] Circulation rate depends on an energy balance around duty
required to vaporize the water 112 and temperature difference
between the liquid 120 entering and exiting the vessel 100.
Increasing temperature of the liquid 120 decreases required
circulation rates for the liquid 120 but may be limited by thermal
stability or coking of the liquid 120. Mean residence time of the
liquid 120 in the vessel 100 provides sufficient thermal capacity
to dampen perturbations in feed rate of the water 112 or
circulation rate or temperature of the liquid 120.
[0027] The circulation loop 122 may further include a purge 126 and
a makeup inlet 128 for replacing any of the liquid 120 purged with
fresh supply. This purging and replacement of the liquid 120
prevents problems from buildup of contaminants resulting from the
heating or transferred to the liquid 120 during vaporization of the
water 112. Organic contaminants in the water 112 may remain with
the liquid 120 also such that one benefit of utilizing the
hydrocarbons for the liquid 120 is that these organics can form
part of the liquid 120 without requiring any treatment. Filters
disposed along the circulation loop 122 may also help keep the
liquid 120 clean by solids removal of inorganic material deposited
by the water 112.
[0028] With the liquid 120 heated, contact of the water 112 with
the liquid 120 within the vessel 100 thus results in vaporization
of the water 112 into steam 130 output from an overhead of the
vessel 100. The steam 130 rises in the vessel for separation from
the liquid 120 and is then conveyed to the injection well 101 for
introduction into the formation. In some embodiments, a
fractionation column provides the vessel 100 to facilitate
separation and enable pulling off separate streams for the steam
130 and any light hydrocarbons if not desired for passing through
to the injection well 101.
[0029] For some embodiments, separation of the water 112 from the
hydrocarbon products 110 occurs at a central processing facility
132 separate and remote (e.g., at least 100 meters or 1 kilometer)
from a well pad 134 where the vessel 100 is disposed. Producing
steam at the pad 134 (i.e., less than 100 meters from the injection
well 101) instead of the central processing facility 132 enables
the steam pressure to be lower (e.g., between 5000 and 10,000
kilopascals) and therefore the steam temperature to be lower as
well (e.g., between 260.degree. C. and 350.degree. C.). These
parameter requirement changes in turn allow the liquid 120 with
relative higher differential temperature to transfer more sensible
heat per pound of liquid 120 if at the pad 134 than at the central
processing facility 132.
[0030] Placement of the vessel 100 at the pad 134 therefore enables
decreasing circulation rate needed for the liquid 120. The
injection of the solvent 114 further lowers the circulation rate
required for the liquid 120. By way of example, location of the
vessel 100 at the pad 134 along with the solvent 114 use may lower
the circulation rate by 60% compared to vaporizing the water 112
alone at the central processing facility 132 (i.e., a reduction in
liquid 120 to steam 130 ratio from 10:1 to 4:1).
[0031] FIG. 2 illustrates a bitumen based system with a steam
generator vessel 200, an injection well 201 and a production well
202 that are operated for steam generation without first separating
a mixture 204 of water and hydrocarbons from the production well
202. A feed pump 216 pressurizes the mixture 204 that is then
preheated in a furnace or heat exchanger 217 prior to introduction
into the vessel 200. In some embodiments, the mixture 204 may
receive heat from a sales portion 210 of the hydrocarbons.
[0032] Upon entry into the vessel 200, some flashing of the water
in the mixture 204 may occur upon expansion into relative lower
pressure conditions of the vessel 200. Remaining water in the
mixture 204 vaporizes upon contact with hot bitumen 220 collected
in a bottom of the vessel 200 and formed of the hydrocarbons in the
mixture 204 that are heated in a circulation loop 222. The
circulation loop 222 contains a recycle pump 221 that passes the
bitumen 220 from the vessel 200 to a desalter 223 and then a
furnace 224 before returning the bitumen 220 to the vessel 200.
[0033] The desalter 223 removes inorganic material from the bitumen
220. Some of the bitumen 220 exiting the desalter 223 provides the
sales portion 210 of the hydrocarbons for pipeline or transport to
a refinery for further processing. The furnace 224 heats a
remainder of the bitumen 220 from the desalter 223 to a temperature
above a boiling point of the water at the pressure conditions in
the vessel 200.
[0034] For some embodiments, overhead from the vessel 200 passes
through a separation device 229 that may include demisters,
separators, fractionators and/or particulate filters. The device
229 removes entrained liquids and/or solids 233 and/or condensable
hydrocarbons 231 vaporized by the bitumen 220 or resulting from
cracking of the bitumen 220. The condensable hydrocarbons 231 may
mix back into the sales portion 210 of the hydrocarbons or have a
portion mixed back for injection into the formation as a
solvent.
[0035] Steam 230 exits the device 229 and is conveyed to the
injection well 201. Some embodiments may introduce steam in the
furnace 224 to mitigate fouling or superheat and inject steam in
the bottom of the vessel 200 to facilitate vaporization of the
water. Since separation of the mixture 204 occurs with the vessel
200, this approach eliminates need for independent de-oiling
equipment.
[0036] Residence time of the bitumen 220 in the vessel 200 provides
sufficient soak time for visbreaking of the bitumen 220. Exemplary
soaking times may range from 5 minutes to 1 hour with the bitumen
heated in the furnace 224 to at least 385.degree. C. The
circulation loop 222 may incorporate various approaches to enhance
the visbreaking, such as radiation thermal cracking or hydrodynamic
cavitation. The visbreaking lowers viscosity and density of the
bitumen 220 and hence the sales portion 210 making the sales
portion 210 more valuable and easier to transport while requiring
less diluents than the bitumen without such upgrading.
[0037] FIG. 3 shows a brine based system utilizing a steam
generator vessel 300, an injection well 301 and a production well
302 similar to other embodiments. In operation, a mixture 304 from
the production well 302 flows to a separator 306 that divides the
mixture 304 into separate streams of hydrocarbons 310 and water
312. A feed pump 316 supplies the water 312 at desired pressure
into the vessel 300.
[0038] The vessel 300 contains a pool of brine 320 heated to a
temperature above a boiling point of the water 312 introduced into
the vessel 300. In some embodiments, an aqueous solution of sodium
chloride forms the brine 320 that may have at least 50 grams of
salt per liter of water. Such salt concentrations thus exceed
amount of salt present in the water 312 input into the vessel 300
for vaporization.
[0039] For some embodiments, heating of the brine 320 may occur by
heat transfer with another fluid such as hot gas or liquids. For
example, an exchanger circuit pump 321 may circulate molten sodium
through a furnace 324 to reheat the sodium that is then passed
through heating coils 325 immersed in the brine 320 disposed in the
vessel 300. The furnace 324 heats the sodium to a temperature, such
as above 500.degree. C., selected above an operating temperature in
the vessel 300 such that heat transfers from the sodium through
walls of the coils 325 to the brine 320 and leaves the coils 325 at
a lower temperature to be reheated.
[0040] Similar to other steam generation techniques described
herein, the water 312 vaporizes upon contacting the brine 320 with
resulting steam 330 that rises in the vessel 300 being withdrawn
and conveyed to the injection well 301. Organic impurities within
the water 312 may partition between the steam 330 and the brine
320. Any volatile organics that pass through with the steam 330 may
flow to the injection well 301 and act as solvent in recovery of
the hydrocarbons.
[0041] Inorganic and nonvolatile organic contaminates in the water
312 remain in the brine 320 once the water 312 vaporizes. The brine
320 may remain in constant agitation by mixers or recirculation,
such as provided with a brine pump 350. This agitation prevents the
brine 320 from fouling on the coils 325, inlets for the water 312
or walls of the vessel 300. While part of the brine 320 output by
the brine pump 350 returns to the vessel 300, a portion of the
output from the brine pump 350 goes for further treatment thereby
protecting the pool of brine 320 in the vessel 300 from excessive
buildup of the contaminates.
[0042] In some embodiments, this further treatment of purged brine
includes an optional additional steam recovery unit incorporating
(as depicted with a dashed box) a booster pump 352, a brine heater
354 and an auxiliary steam generator 356. Such additional steam
generation boosts a water recycle rate associated with the
hydrocarbon recovery operation and may facilitate reaching
regulated water recycle levels. The booster pump 352 raises
pressure of the brine to above an operating pressure of the vessel
300 and hence output pressure of the steam 330. The brine heater
354 then raises temperature of a pressurized output from the
booster pump 352 to still be at a temperature, such as at least
365.degree. C., below a boiling point of the brine at this
pressure, such as at least 20,000 kilopascals. Fluid flow output
from the brine heater 354 enters the steam generator 356 where
flashed to produce steam at a pressure at least as high as the
steam 330 from the vessel 300 for combination therewith.
[0043] Liquids remaining in the steam generator 356 from incomplete
flashing into the steam pass to a flash drum 358 for flashing at a
lower pressure than the steam 330 from the vessel 300. A vapor
overhead 359 from the flash drum 358 thus contains steam of
relative lower pressure, such as less than 500 kilopascals, for
reuse in applications such as process heating and/or condensing and
recycling to mix back with the water 312. If not otherwise
disposed, liquids remaining in the flash drum 358 from incomplete
flashing into the overhead 359 may pass to a thermal oxidizer 360.
Effluents from the oxidizer 360 include flue gas 362 including
products from combustion of the organic contaminates in the water
312 that partitioned to the brine 320 and solids 364 suitable for
landfill disposal.
[0044] FIG. 4 illustrates another system also employing a steam
generator vessel 400, an injection well 401 and a production well
402 with further indirect heating used to maintain temperature in
the vessel 400. In operation, a mixture 404 from the production
well 402 flows to a separator 406 that divides the mixture 404 into
separate streams of hydrocarbons 410 and water 412. A feed pump 416
pressurizes the water 412 supplied into the vessel 400 where the
water 412 contacts a heated thermal transfer liquid 420 to generate
steam 430 conveyed to the injection well 401.
[0045] A recycle pump 421 circulates the liquid 420 through a
circulation loop 422 where the liquid 420 is reheated to sustain
the steam generation. The liquid 420 in the circulation loop 422
passes through a gas-liquid contactor 424 to achieve this reheating
before return of the liquid 420 back to the vessel 400. The
gas-liquid contactor 424 may avoid problems such as fouling on
heater tubes that may occur depending on fluid selected as the
liquid 420. For example, use of bitumen or other heavy hydrocarbons
as the liquid 420 may result in coking if heated in a furnace.
[0046] A thermal transfer gas passes through the gas-liquid
contactor 424 along a gas loop 475 and may include hydrocarbon gas,
such as methane or butane, nitrogen or argon. A heat exchanger 476
may provide initial heat transfer from the gas loop 475 to the
liquid 420 before further heating of the gas in a furnace 478. Once
heated, the gas rises through the gas-liquid contactor 424 and
contacts the liquid 420 to transfer heat to the liquid 420. In
addition to a compressor 480 to supply the gas to the gas-liquid
contactor 424, the circulation loop 475 may further include a purge
to allow for removal of accumulated water that carries over and a
makeup inlet for replacement of this purged gas. A purifier 492
removes any carryover of the gas into the liquid 420 within the
circulation loop 422 and that exits the gas-liquid contactor 424
and is pressurized by a booster pump 494 for reentry into the
vessel 400.
[0047] FIG. 5 shows yet another system also employing a steam
generator vessel 500, an injection well 501 and a production well
502 with an alternative indirect heating approach used to maintain
temperature in the vessel 500. As with other operations described
herein, a mixture 504 from the production well 502 flows to a
separator 506 that divides the mixture 504 into separate streams of
hydrocarbons 510 and water 512. A feed pump 516 pressurizes the
water 512 supplied into the vessel 500 where the water 512 contacts
a heated thermal transfer liquid 520 to generate steam 530 conveyed
to the injection well 501.
[0048] Still like the system in FIG. 4, a first recycle pump 521
circulates the liquid 520 through a circulation loop 522 where the
liquid 520 is reheated by a thermal transfer gas in a gas loop 575
to sustain the steam generation. A furnace 578 keeps the gas hot
that is sent to a gas-liquid contactor 524. The liquid 520 in the
circulation loop 522 passes through a heat exchanger 576 and the
gas-liquid contactor 524 to achieve this reheating before return of
the liquid 520 back to the vessel 500.
[0049] After contact with the liquid 520 in the gas-liquid
contactor 524, a first heat exchanger or chiller 582 further cools
the gas such that water is removed in a first purifier 584. A
second chiller 586 then condenses the gas into a liquid phase for
removal of hydrocarbons lighter than the gas in a second purifier
590 and pressurizing in a pump 580 for re-vaporization into the gas
in the furnace 578 in order to resupply the gas to the gas-liquid
contactor 524. A third purifier 592 removes any carryover of the
gas into the liquid 520 within the circulation loop 522 and that
exits the gas-liquid contactor 524. A second recycle pump 594 then
pressurizes the liquid 520 for reentry into the vessel 500.
[0050] Features shown in only one figure, like the nozzle 118 or
injection of the solvent in FIG. 1, and described once for
succinctness may nevertheless be incorporated with any steam
generator vessels described herein and illustrated in other
figures. For example, filtering and separating steam output from
any of the vessels may occur before injection. While shown in an
embodiment with the brine as the thermal transfer liquid, heating
coils within any of the vessels may provide for reheating of any
other thermal transfer liquid.
[0051] In closing, it should be noted that the discussion of any
reference is not an admission that it is prior art to the present
invention, especially any reference that may have a publication
date after the priority date of this application. At the same time,
each and every claim below is hereby incorporated into this
detailed description or specification as additional embodiments of
the present invention.
[0052] Although the systems and processes described herein have
been described in detail, it should be understood that various
changes, substitutions, and alterations can be made without
departing from the spirit and scope of the invention as defined by
the following claims. Those skilled in the art may be able to study
the preferred embodiments and identify other ways to practice the
invention that are not exactly as described herein. It is the
intent of the inventors that variations and equivalents of the
invention are within the scope of the claims while the description,
abstract and drawings are not to be used to limit the scope of the
invention. The invention is specifically intended to be as broad as
the claims below and their equivalents.
* * * * *