Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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STEAM DRIVE DIRECT CONTACT STEAM GENERATION
BACKGROUND OF THE INVENTION
1. Field of the Invention
[01] This application relates to a system and method for producing steam from
contaminated water feed for Enhanced Oil Recovery (EOR). This invention
relates to processes for
directly using steam energy, preferably superheated dry steam, for generating
additional steam from
contaminated water by direct contact, and using this produced steam for
various uses in the oil industry
and possibly in other industries as well. The produced steam can be injected
underground for Enhanced
Oil Recovery. It can also be used to generate hot process water at the mining
oilsands industry. The high
pressure drive steam is generated using commercially available, non-direct
steam boiler, co-gen, OTSG
or any steam generation system or steam heater. Contaminates, like suspended
or dissolved solids
within the low quality water feed, can be removed in a stable solid (former
Liquid Discharge) system.
The system can be integrated with combustion gas fired DCSG (Direct Contact
Steam Generator) for
consuming liquid waste streams or with distillation and systems.
[02] The injection of steam into heavy oil formations was proven to be an
effective method
for FOR and it is the only method currently used commercially for recovery of
bitumen from deep
underground oilsand formations in Canada. It is known that FOR can be achieved
where combustion
gases, mainly C02, are injected into the formation, possibly with the use of
DCSG as described in my
previous applications. The problem is that oil producers are reluctant to
implement significant changes
to their facilities, especially if they include changing the composition of
the injected gas to the
underground formation and the risk of corrosion in the carbon steel pipes due
to the presence of the
C02. Another option to fulfill this requirement and generate steam from low
grade produced water with
ZLD is to operate the DCSG with steam instead of a combustion gas mixture that
includes, in addition to
steam, other gases like nitrogen, carbon dioxide, carbon monoxide and other
gases. The driving steam is
generated by a commercially available non-direct steam generation facility.
The driving steam is directly
used to transfer liquid water into steam and solid waste. In FOR facilities
most of the water required for
steam generation is recovered from the produced bitumen-water emulsion. The
produced water has to
be extensively treated to remove the oil remains that can damage the boilers.
This process is expensive
and consumes large amount of chemicals. The SD-DCSG (Steam Drive - Direct
Contact Steam Generator)
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can consume the contaminated water feed for generating steam. The SD-DCSG can
be stand alone
system or can be integrated with combustion gas DCSG as described in this
application. The proposed
SD-DCSG is also suitable for oilsands mining projects where the FT (Fine
Tailings) or MFT (Mature Fine
Tailings) are heated and converted to solids and steam using the driving steam
energy. The produced
steam from the SD-DCSG can be used to heat the process water in a direct or
non-direct heat exchange.
The hot process water is mix with the mined oilsands ore during the extraction
process.
[03] The steam for the SD-DCSG can be provided directly from a power station.
The most
suitable steam will be the medium pressure, super-heated steam as typically
fed to the second or third
stage of steam turbine. A cost efficient, hence effective system will be to
employ a high pressure steam
turbine to generate electricity. The discharge steam from the turbine, at a
lower pressure, can be
recycled back to the boiler re-heater to generate a super heated steam which
is effective as a driving
steam. Due to the fact that the first stage turbine, which is the smallest
size turbine, produces most of
the power (due to a higher pressure), the cost per Megawatt of the steam
turbine will be relatively low.
The efficiency of the system will not be affected as the superheated steam
will be used to drive the SD-
DCSG directly and generating injection steam for enhanced oil recovery unit
with Zero Liquid Discharge
(ZLD). A ZLD facility is more environmentally friendly compared to a system
that generates reject water
and sludge.
[04] The definition of "Steam Drive - Direct Contact Steam Generation" (SD-
DCSG) is that
steam is used to generate additional steam from direct contact heat transfer
between the liquid water
and the combustion gas. This is accomplished through the direct mixing of the
two flows (the water and
the steam gases). In the SD-DCSG, the driving steam pressure is similar to the
produced steam pressure
and the produced steam is a mixture of the two.
[05] The driving steam is generated in a Non-Direct Steam Generator (like a
steam boiler
with a steam drum and a mud drum) or "Once Through Steam Generator" (OTSG)
COGEN that uses the
heat from a gas turbine to generate steam or any other available design. The
heat transfer and
combustion gases are not mixed and the heat transfer is done through a wall
(typically a metal wall),
where the pressure of the generated steam is higher than the pressure of the
combustion. This allows
for the use of atmospheric combustion pressure. The product is pure steam (or
a steam and water
mixture, as in the case of the OTSG) without combustion gases.
[06] There are patents and disclosures issued in the field of the present
invention. US patent
No. 6,536,523 issued to Kresnyak et al. on March 25, 2003 describes the use of
the blow-down heat as
the heat source for water distillation of de-oiled produced water in a single
stage MVC water distillation
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unit. The concentrated blow-down from the distillation unit can be treated in
a crystallizer to generate
solid waste.
[07] US Patent application 12/702,004 filed by Minnich et al. and published on
August 12,
2010 describes a heat exchanger that operates on steam for generating steam in
an indirect way from
low quality produced water that contains impurities. In this disclosure, steam
is used indirectly to heat
the produced water that include contaminates. By using steam as the heat
transfer medium the direct
exposure of the low quality water heat exchanger to fire and radiation is
prevented, thus there will be
no damage due to the redaction of the heat transfer. The concentrated brine is
collected and delivered
to disposal or to multi stage evaporator to recover most of the water and
generates a ZLD (Zero Liquid
discharge) system. The heat transfer surfaces between the steam and the
produced water will have to
be clean or the produced water will have to be treated. The concentrated
brine, possibly with organics,
will be treated in a low pressure, low temperature evaporator to increase
their concentration; the
higher the concentration is, the lower the temperature. In my application, due
to the direct approach of
the heat transfer, the system in ZLD with the highest concentration, possibly
up to 100% liquid recovery
while generating solid waste, is at the first stage at the higher temperature
due to the direct mixture
with the superheated dry steam that converts the liquid into gas and solids.
[08] US patent No. 7,591,309 issued to Minnich et al. on September 22, 2009
describes the
use of steam for operating a pressurized evaporation facility where the
pressurized vapor steam is
injected into underground formation for EOR. The steam heats the brine water
which is boiled to
generate additional steam. To prevent the generation of solids in the
pressurized evaporator, the
internal surfaces are kept wet by liquid water and the water is pre-treated to
prevent solid build up. The
concentrated brine is discharged for disposal or for further treatment in a
separate facility to achieve a
ZLD system. To achieve ZLD, the brine evaporates in a series of low pressure
evaporators (Multi Effect
Evaporator).
[09] US patent No. 6,733636, issued to Heins on May 11, 2004, describes a
produced water
treatment process with a vertical MVC evaporator.
[10] US Patent No. 7,578,354, issued to Minnich et al. on August 25, 2009,
describes the use
of MED for generating steam for injecting into an underground formation.
[11] US Patent No. 7,591,311, issued to Minnich et al. on September 22, 2009,
describes
evaporating water to produce distilled water and brine discharge, feeding the
distilled water to a boiler,
and injecting the boiler blow-down water from the boiler to the produced
steam. The solids and possibly
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volatile organic remains are carried with the steam to the underground oil
formation. The concentrated
brine is discharged in liquid form.
[12] This invention's method and system for producing steam for extraction of
heavy
bitumen includes the steps as described in the patent figures.
[13] The advantage and objective of the present invention are described in the
patent
application and in the attached figures.
[14] These and other objectives and advantages of the present invention will
become
apparent from a reading of the attached specifications and appended claims.
SUMMARY OF THE INVENTION
[15] The method and system of the present invention for steam production for
extraction of
heavy bitumen by injecting the steam to an underground formation or by using
it as part of an above
ground oil extraction facility includes the following steps: (1) Generating a
super heated steam stream.
The steam is generated by a commercially available non-direct steam generation
facility , possibly as
part of a power plant facility; (2) Using the generated steam as the hot gas
to operate a DCSG (Direct
Contact Steam Generator); (3) Mixing the super heated steam gas with liquid
water with significant
levels of solids, oil contamination and other contaminate; (4) Directly
converting liquid phase water into
gas phase steam; (5) Removing the solid contaminates that were supplied with
the water for disposal or
further treatment; (6) Using the generated steam for EOR, possibly by
injecting the produced steam into
an underground oil formation through SAGD or CSS steam injection well.
[16] In another embodiment, the invention can include the following steps: (1)
Generating a
super heated steam stream. The steam is generated by heating a steam stream in
non-direct heat
exchanger; (2) Using the generated steam as the hot gas to operate a DCSG
(Direct Contact Steam
Generator); (3) Mixing the super heated steam gas with liquid water with
significant levels of solids, oil
contamination and other contaminates; (4) Directly converting liquid phase
water into gas phase steam;
(5) Removing the solid contaminates that were supplied with the water for
disposal or further
treatment; (6) Recycling a portion of the generated steam back to the heating
process of (1) to be used
as hot gas operating the DCSG. The recycled steam can be cleaned to remove
contaminates that can
affect the heating process (like silica). The cleaning process can include any
type of filter, precipitators
or wet scrubbers. Chemicals (like caustic, magnesium salts or any other
commercially available
chemicals) can be added to the wet scrubber to remove contaminates from the
steam flow.
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[17] In another embodiment, part of the generating steam is condensed and used
to wash
the produced steam from solid particles in a wet scrubber. Chemicals can be
added to the liquid water
to remove contaminates. A portion of the liquid water is recycled back and
mixed with the superheated
steam to transfer it into gas and solids. A portion from the scrubbed
saturated steam flow can be
recycled and heated to generate a super heated "dry" steam flow to drive the
SD-DCSG and change the
liquid flow into steam.
[18] In another embodiment, the scrubbed saturated steam, after the solids
were removed,
can be condensed to generate contaminate free liquid water, at a saturated
temperature and pressure.
The liquid water can be pumped and fed into a commercially available non-
direct steam boiler for
generating super heated steam to drive the SD-DCSG for transferring the liquid
contaminated water into
gas and solids.
[19] In another embodiment, the SD-DCSG is integrated with DCSG that uses
combustion
gases as the heat source. In that embodiment, the discharge from the SD-DCSG
can be in a liquid form
and it can be used as the water source for the combustion gas driven DCSG.
[20] The present invention can be used to treat contaminated water by SD-DCSG
in different
industries like the power industry or chemical industry where there is a need
to recover the water from
contaminated water stream to generate steam with zero liquid discharge.
[21] The system and method different aspects of the present invention are
clear from the
following figures.
DETAILED DESCRIPTION OF THE DRAWINGS
[22] FIGURES 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the method
and the
system.
[23] FIGURE 2 shows a block diagram of the invention. Flow 9 is superheated
steam. The
steam pressure can be from 1 to 150 bar and the temperature can be between
150C and 600C. The
steam flows to enclosure 11 which is a SD-DCSG. Contaminated produced water 7,
possibly with organic
contaminates, suspended and dissolved solids, is also injected into enclosure
11 as the water source for
generating steam. The water 7 evaporates and is transferred into steam. The
remaining solids 12 are
removed from the system. The generated steam 8 is at the same pressure as that
of the drive steam 9
but at a lower temperature as a portion of its energy was used to drive the
liquid water 7 through a
phase change. The generated steam is also at a temperature that is close to
the saturated temperature
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of the steam at the pressure inside enclosure 11. The produce steam can be
further treated 13 to
remove carry-on solids, reducing its pressure and possibly removing additional
chemical contaminates.
Then the produced steam is injected into an injection well for EOR.
[24] FIGURE 2A shows a schematic of a vertical SD-DCSG. Dry steam 9 is
injected to vessel 11
at its lower section. At the upper section, water 7 is injected 3 directly
into the up-flow stream of dry
steam. The water evaporates and is converted to steam at lower temperature but
at the same pressure.
Contaminates that were carried on with the water are turned into solids and
possibly gas (if the water
includes hydrocarbons like naphtha). The produced gas, mainly steam, is
discharged from the SD-DCSG
at the top. To prevent carried-on water droplets, demister packing 5 can be
used at the top of SD-DCSG
enclosure 11. The solids 12 are removed from the system from the bottom 1 of
the vertical enclosure
where they can be disposed of or further treated.
[25] FIGURE 2B shows a block diagram of the invention. This figure is similar
to Figure 2 but
with an additional solids removal system as described in Block 15. Block 15
can include any commercially
available Solid - Gas separation unit. In this particular figure, cyclone
separator 19 and electrostatic
separation are presented. High temperature filters, that can withstand the
steam temperature, possibly
with a back-pressure cleanup system, can be used as well. The steam flow
leaving the SD-DCSG can
include solids from the contaminate water 7. A portion of the solids 12 can be
recovered in a dry or wet
form from the bottom of the steam generation enclosure 11. The carry-on solids
14 can be recovered
from the gas flow 8 in a dry form for disposal or for further treatment.
[26] FIGURE 2C is another embodiment of a reaction chamber apparatus of a high-
pressure
steam drive direct contact steam generator of the present invention. A similar
structure can be used
with DCSG that uses combustion gas as the heat source to convert the liquid
water into steam. A
counter-flow horizontally-sloped pressure drum 10 is partially filled with
chains 11 that are free to move
inside the drum and are internally connected to the drum wall. A parallel flow
design can be used as
well. The chains increase the heat transfer and removes solids build-up. Any
other design that includes
internal embodiments that are free to move or moving with the rotating
enclosure and lifting solids and
liquids to enhance their mixture with the flowing gas can be used as well. The
drum 10 is a pressure
vessel and is continually rotating, or rotating at intervals. At a low point
of the sloped vessel 10, hot dry
steam 8 is generated by a separate unit, like the pressurized boiler (not
shown), and is injected into the
enclosure 8. The boiler is a commercially available boiler that can burn any
available fuel like coal, coke,
or hydrocarbons such as untreated heavy low quality crude oil, VR (vacuum
residuals), asphaltin, coke,
or any other available carbon or hydrocarbon fuel. The pressure inside the
rotating drum can vary
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between lbar and 100bar, according to the oil underground formation. The
vessel is partially filled with
chains 10 that are internally connected to the vessel wall and are free to
move. The chains 10 provide an
exposed regenerated surface area that works as a heat exchanger and
continually cleans the insides of
the rotating vessel. The injected steam temperature can be any temperature
that the boiler can supply,
typically in the range of 200C and 800C. Low quality water, like mature
tailing pond water, rich with
solids and other contaminants (like oil based organics) or contaminated water
from the produced water
treatment process are injected into the opposite higher side of the vessel at
section 4 where they are
mixed with the driving dry steam and converted into steam at a lower
temperature. This heat exchange
and phase exchange continues at section 3 where the heavy liquids and solids
move downwards,
directly opposite to the driving steam flow. The driving steam injected at
section 2, which is located at
the lower side of the sloped vessel, moves upwards while converting liquid
water to gas. The heat
exchange between the dry driving steam to the liquids is increased by the use
of chains that maintain
close contact, both with the hot steam and with the liquids at the bottom of
the rotating vessel. The
amount of injected water is controlled to produce steam in which the dissolved
solids become dry or
high solids concentration slurry and most of the liquids become gases.
Additional chemical materials
can be added to the reaction, preferably with any injected water. The
rotational movement regenerates
the internal surface area by mobilizing the solids to the discharged point.
The heat transfer in section 3
is sufficient to provide a homogenous mixture of gas steam and ground - up
solids or high viscosity
slurry. Most of the remaining liquid transitions to gas and the remaining
solids are moved to a discharge
point 7 at the lower internal section of the rotating vessel near the rotating
pressurized drum 10 wall.
The solids or slurry are released from the vessel 10 at a high temperature and
pressure. They undergo
further processing, such as separation and disposal.
[27] FIGURE 2D shows a schematic of a vertical SD-DCSG. It is similar to Fig.
2A with the
following changes. Vessel 11 includes a liquid water 1 bath at its bottom. The
water maintained at a
saturated temperature. Saturated water is recycled and dispersed 3 into the up-
flow flow of dry steam
9. The dispersed water evaporated into the up-flowing steam. Contaminates that
were carried on with
the water are turned into solids and possibly gas (if the water includes
hydrocarbons). The produced
gas, mainly steam, is discharged from the SD-DCSG at the top. Portion of the
saturated water 1
dispersed at the up-flow stream of dry steam. The water evaporates converted
to a lower temperature
steam. Solids are curried with the up-flow gas 8. Over-sized solids 12 can be
removed from the system
from the bottom 1 of the vertical enclosure in a slurry form for further
treatment.
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[28] FIGURE 2E shows a schematic of a SD-DCSG integrated into an open mine
oilsands
extraction plant for generating the hot extraction water while consuming the
Fine Tailing generated by
the extraction process. . Flow 9 is superheated steam. The steam flows to
enclosure 11 which is a SD-
DCSG. Fine Tailings (FT) contaminated produced water 7, is also injected into
enclosure 11 as the water
source for generating steam. The water component in 7 evaporates and is
transferred into steam. The
remaining solids 12 are removed from the system. The generated steam 8 is at
the same pressure as
that of the drive steam 9 but at a lower temperature as a portion of its
energy was used to drive the
liquid water 7 through a phase change. The generated steam is also at a
temperature that is close to (or
slightly higher from) the saturated temperature of the steam at the pressure
inside enclosure 11. The
produce steam is fed into a heat exchanger / condenser 13. In figure 2E, a non-
direct heat exchanger is
described. A direct heat exchanger can be used as well. The produced steam
condensation energy is
used to heat the flow of cold extraction process water 52 to generate a hot
process water 52A flow at
temperature of 70-90C. The produced hot process water can be used in Block A
for tarsands extraction.
The hot condensate 10 that is generated from steam flow 8 can be added to the
process water 52A or
use for other usage as a water source for High Pressure steam boiler, as an
example. In case that NCG
were generated 17, they are recovered for further use. (For FT 9 that contains
low levels of organics, low
amounts of NCG will be generated. With the use of direct contact heat exchange
between the process
water 52 and the produced steam 8 at 13 (not shown), the low levels of NCG
will be dissolved and
washed by the large amount of process water 14). Block A is a typical open
mine extraction oilsands
plant as described, for example in Block 5 in Figure 8. Flow 7 is fine
tailings generated during the
extraction process. Flow 14 is additional fine tailings from other sources,
like MFT from a tailing pond
(not shown). The driving steam 9 can be generated by compressing and heating a
portion of the
generated steam as described in Figure 3 (not shown).
[29] FIGURE 2F shows a SD-DCSG with a non-direct heat exchanger to heat the
process
water and with the combustion of the NCG hydrocarbons as part of generating
the driving steam. Fine
tailings or MFT 7 are injected to a SD-DCDG. In figure2F a vertical fluid bed
SD-DCSG is schematically
presented. Any other SD-DCSG can be used as well like the horizontal SD-DCDG
presented in Figures 3A,
3B, 3C or any other design. The FT 7 is mixed with dry super-heated steam flow
9 that is used as the
energy source to transfer the liquid water phase in flow 7 to gas (steam)
phase by direct contact heat
exchange. The FT 7 solids removed in a stable form 12 where they can be
economically disposed and
support traffic. The produced steam 8 is condensed in a non-direct heat
exchanger / condenser 13. The
water condensation heat is used to heat the extraction process water 14. With
some tailings types, NCG
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(Non Condense Gas) 17 are generated due to the presents of hydrocarbons like
solvents used in the
froth treatment or oil remains that were not separated and remained with the
tailings. The NCG 17 is
burned together with other fuel 20, like natural gas, syngas or any other
fuel. The combustion heat is
used, through non-direct heat exchange, to produce the superheated driving
steam 9 used to drive the
process. The amount of energy in the NCG hydrocarbon 17 recovered from typical
oilsands tailings, even
from a solvent froth treatment process, is not sufficient to generate the
steam 9 to drive the SD-DCSG. It
can provide only a small portion from the process heat energy used to generate
the driving steam 9.
One option is to use a standard boiler 18 design to generate steam from liquid
water feed 19 from a
separate source. Another option is to use portion of the produced steam
condensate 23 as the liquid
water feed to generate the driving steam 9. The condensate will be treated to
bring it to a BFW quality.
Treatment units 24 are commercially available. Another option to generate the
driving steam 9 is to
recycle portion of the produced steam 8. The recycled produced steam 21 is
compressed 22. The
compression is needed to overcome the pressure drop due to the recycle flow
and generate the flow
through the heater 18 and the SD-DCSG 11. The compression can be done using
steam ejector with high
pressure additional steam or with the use of any available low pressure
difference mechanical
compressor. The recycled produce steam 21, possibly after additional cleaning,
like wet scrubbing, to
remove contaminates like silica, is indirectly heated by combustion heater 18.
[301 FIGURE 3 is an illustration of one embodiment of the present invention
without using an
external water source for the driving steam. SD-DCSG 30 includes a hot and dry
steam injection 36. The
steam is flowing upwards where low quality water 34 is injected to the up flow
steam. At least a portion
of the injected water is converted into steam at a lower temperature and at
the same pressure as the
dry driving steam 36. The generated steam can be saturated ("wet") steam at a
lower temperature than
the driving steam. A portion of the generated steam 32 is recycled through
compressing device 39. The
compression is only designed to create the steam flow through heat exchanger
38 and create the up
flow in the SD-DCSG 30. The compressing unit 39 can be a mechanical rotating
compressor. Another
option is to use high pressure steam 40 and inject it through ejectors to
generate the required over
pressure and flow in line 36. Any other commercial available unit to create
the recycle flow 36 can be
used as well. The produced steam, after its pressure slightly increased to
generate the recycle flow 36,
and possibly after contaminates are removed in a dry separator or wet scrubber
to protect the heater,
flows to heat exchanger 38 where additional heat is added to the recycled
steam flow 32 to generate a
heated "dry" steam 36. This steam is used to drive the SD-DCSG as it is
injected into its lower section 30
and the excess heat energy is used to evaporate the injected water and
generate additional steam 31.
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The heat exchanger 38 is not a boiler as the feed is in gas phase (steam).
There are several commercial
options and design to supply the heat 37 to the process. The produced steam 31
or just the recycled
produced steam 32 can be cleaned from solids carried with the steam gas by an
additional commercially
available system (not shown). The system can include solid removal; this heat
exchanger can be any
commercially available design. The heat source can be fuel combustion where
the heat transfer can be
radiation, convection or both. Another possibility can be to use the design of
the re-heat heat exchanger
typically used in power station boilers to heat the medium / low pressure
steam after it is released from
the high pressure stages of the steam turbine. This option is schematically
Shawn on figure 3. Typically,
the re-heater 40 supplies the heat to operate the second stage (low pressure)
steam turbine.
Accordingly the feed to re-heater is saturated or close to saturated medium-
low steam. As such,
minimizing the re-heater design conversion changes to heat the generated steam
31 for generating the
superheated steam 36. If an existing stem power plant is used, the
supercritical high-pressure steam can
be used to drive a high pressure steam turbine, while the remain heat can be
used through the re-
heater to provide the heat 37 to drive the steam generation facility. A high
pressure steam turbine has
smaller dimensions and TIC (Total Installed Cost) compared to medium / low
pressure steam turbine per
energy unit output.
[31] FIGURE 3A is an illustration of one embodiment of the present invention.
It is similar to
Figure 3 with the use of a rotating SD-DCSG. The driving superheated ("dry")
steam 36 is injected into
rotating pressurized enclosure 30. The rotating SD-DCSG enclosure consumes
liquid water 34, possibly
with solid and organic contaminations, and generates lower temperature steam
31 and solid waste 35
that can be disposed in a landfill and support traffic. The rotating SD-DCSG
30 is described in Figure 2C.
[32] FIGURE 3B is an illustration of a parallel flow SD-DCSG. It is similar to
Figure 3A with the
use of a parallel flow direct contact heat exchange between the liquid water
and the fry steam. The
driving superheated ("dry") steam 36 is injected into rotating pressurized
enclosure 30. Liquid water 34,
possibly with solid and organic contaminations, is injected together with the
driving steam at the same
side of the enclosure. Lower temperature produced steam 31 and solid waste 35
that can be disposed in
a landfill and support traffic. The driving superheated steam is generated by
recycling portion of the
produced steam 32. The recycled produced steam is compressed to overcome the
pressure loss and
generate the floe. It is non-directly heated 38 and recycled back 36 to the SD-
DCDG 30.
[33] FIGURE 3C is an illustration of a SD-DCSG with stationary enclosure and
an internal
rotating element. Super heated driving steam 36 is injected into enclosure 30.
Low quality liquid water
with high levels of contaminates like Fine Tailings generated by an open mine
oilsands extraction plant,
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are injected to the enclosure. The enclosure is pressurized. The liquid water
evaporated to generate
produced steam 33. The produced steam 33 is at a lower temperature compared to
the superheated
driving steam as it is close to the saturated point due to the additional
water that were evaporate and
converted to steam. The solids that were introduced with the low quality
liquid water 34 removed in a
stable form where they can be disposed of in a land fill and support traffic.
To increase the direct
contact heat transfer within the enclosure 30, a moving internals are used.
The internals can be any
commercial available design that is used to mobilized slurry and solids in a
cylindrical enclosure. A
rotating screw 31 can be used. The rotating movement 32 is provided through a
pressure sealed
connection from outside the enclosure. The screw mobilized the solids and
drives them to the discharge
location where they are discharged from the pressurized enclosure.
[34] FIGURE 3D is an illustration of a modification of figure 3C and 3B for a
steam drive Non-
Direct contact steam generator where the heat supplied by steam to a heated
stationary external
enclosure and an internal rotating element to mobilize the evaporating low
quality solids rich water, like
MFT and the solids . The process includes generating or heating steam 36
through indirect heat
exchange (not shown). Using the generated steam energy 36 to indirectly gasify
liquid water 34 with
solids and organic contaminated, like fine tailings, so as to transfer said
liquid water from a liquid phase
to a gas phase 33. Removing solids 35 to produce solids free gas phase steam
33. The produced steam
can be further condensed to generate heat and water for oil production (not
shown). The hot driving
steam (there is no need in using dry superheated steam as the driving steam)
36 is heating enclosure 30.
Low quality liquid water with high levels of contaminates like Fine Tailings
generated by an open mine
oilsands extraction plant, are injected to the enclosure. The enclosure is
pressurized. The liquid water
evaporated due to non-direct heat transfer from the enclosure 30 to generate
produced steam 33. The
solids that were introduced with the low quality liquid water 34 removed in a
stable form 35 where they
can be disposed of in a land fill and support traffic. To increase the direct
contact heat transfer within
the enclosure 30 and to mobilize the solids and slurry, a moving internals are
used. The internals can be
any commercial available design that is used to mobilized slurry and solids in
a cylindrical enclosure. A
rotating screw 31 can be used. The rotating movement 32 is provided through a
pressure sealed
connection from outside the enclosure. The screw mobilized the solids and
drives them to the discharge
location where they are discharged from the pressurized enclosure. Any other
design (like double screw,
lifting scoops, chains) can be used as well. Condensed water 36A from the
condensing driving steam 36
is recycled where it can be re-heated for generating additional driving steam
36 or for any other use.
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[35] Figure 3E shows a parallel flow and a counter flow steam drive direct
contact steam
generation system. In the parallel flow system 1 liquid water 7, possibly with
high level of suspended
and dissolved solids like fine tailings, produced water, evaporator brine,
brackish water, produced gas,
carbons, hydrocarbons or any available water feed possible with high levels of
contaminates is fed into a
longitude enclosure 5. Superheated dry steam 6 is also fed into the same
longitude enclosure 4 at the
same side where the low quality water is injected where the two flows, the
liquid and the gas are mixed
in direct contact. To enhance the mixing and mobilize the generated slurry or
solids a mechanical energy
is supplied into the enclosure. A possible simple way to supply the mechanical
energy is by a longitude
rotating element 9. There are several designs for such a rotating element that
can includes spiral,
scoops, scrapers or any other commercial available design. It is possible to
use a single rotating unit 11
in a circle enclosure 10. It is also possible to use double rotating units 13
and 14 in an oval enclosure 12
where the multiple rotating units can enhance the mixing and the removal of
solids deposits. In the
parallel system, the produced steam 3 is discharged with the solids rich
slurry or solids at the enclosure
end. To allow efficient heat transfer duration, the enclosure length is longer
than its diameter, typically
the length L is at least twice the diameter D. The steam-solids mixture is
further separated (not shown).
In the counter flow system 15 the low quality liquid flow 18, similar to flow
7 in the parallel flow system
1, is fed to a longitude enclosure with internal rotating element to introduce
mechanical energy to the
enclosure. The superheated driving steam 16 is introduced at the opposite end
of the enclosure where it
is mixed with the flow of liquids 18. The heat energy in the super heated
driving steaml6 is directly
transferred to the liquid water to generate steam. The slurry or solids are
transferred by rotating auger,
possibly with spiral in an opposite direction to the driving steam 16 flow and
discharged from the
longitude system at 17. It is also possible to connect the parallel flow and
the counter flow systems to
each other where the discharge from the first system 3 or 17 still contains
significant levels of liquids,
possible in a slurry form, is fed into the second system 18 or 7.
[36] Figure 3F shows a direct contact steam generating system as shown in
Figure 3E with
solids separation. The direct contact parallel flow steam generator 1 is
similar to figure 3E where the
solid contaminates are removed from the steam flow in a separator 10 through
de-pressurized
collection hopper system that includes valves 12 and 14, de-pressurized
enclosure 13, and solids
discharge 15. The enclosure 10 can include internals to generate cyclone
separation or any other
commercial available solids separation design. A commercial available gas-
solid separation packages
can be added to the discharged flow 20 to remove solids from the gas stream
(not shown). The solids
removed from stream 20 can be discharged through the de-pressurized hopper
system 13.
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[37] FIGURE 3G is a steam drive direct contact steam generator apparatus. It
includes a
vertical enclosure 2 with steam injection points 6 arranged around the
enclosure wall. The injection
flows 5, 9 are arranged to enhance the mixing flow within the vessel and to
protect the enclosure wall
from solids build-ups Water. Liquid water 7 injected into the upper section 1
of the enclosure. The water
injection can include a sprayer to disperse the water and enhance the mixture
between the liquid water
and the steam. The injected water can be low quality produced water or water
from any other source,
like tailings pond water. The injected water 7 can include dissolve or
suspended solids as well as any
other carbon or hydrocarbon contamination. The water is injected at the upper
section - section C.
Super heated dry steam 5 is injected at section B located below the water
injection 7. The dry steam
injected substantially perpendicular to the enclosure wall, possibly with an
angle to enhance the mixture
of the liquid water and the steam and to minimize the contact between the
liquid water and the
enclosure wall to prevent solids deposits build up on the enclosure wall. The
solids rich contaminates 4,
that were introduced to the system with the water feed 7, after most of the
liquid water evaporates into
steam, are collected at the bottom of the enclosure 3 and removed from the
system. The injected steam
9 can be disperse by a nozzle 10 close to the enclosure wall in a way that
part of the steam flow will be
spread and generate a flowing movement that will reduce the potential contact
between the water feed
7 and the enclosure wall. The injected steam 5 and the water feed that was
converted to steam is
released in a gas flow 8 from the upper section of the enclosure 1. The steam
flow 8 can flow through a
demister and a separator that can be located internally in section C or
externally to remove water
droplets and solids remains (not shown). The pressure of the produced steam 8
is substantially similar to
the pressure of the superheated driving steam 5, except from a small
difference to generate the up flow
movement, and its temperature is closer to the saturated temperature at the
particular enclosure
pressure due to the evaporation of the feed water 7.
[38] FIGURE 3H is another configuration of a steam drive direct contact steam
generator
apparatus. Sections A and B are described in Figure 3E. Superheated dry steam
6 is injected into section
B. Any liquid water that flows into the up-flow chamber of section B is
converted into steam.
Contaminates, mainly solids, that were carried with the feed water 3 are
removed from the bottom of
the enclosure 9 from section A. The superheated steam 6 flows from section B
into section C located
above B. Section C include a fluid bed 4. This fluid bed includes liquid,
solids and slurry supplied with the
feed water 3. Additional free moving bodies, like sand, found metal particle,
round ceramic particle can
add to the fluid bed 4 to enhance the heat transfer between the up flowing
steam and the slurry from
the water feed 3. The fluid bed section C can include additional steam
injectors (not shown) to mobilize
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the solids and prevent solids build-ups that can block the fluid bed. A direct
steam injection into section
C can be done in intervals in strong bursts to mobilize the fluid bed and
remove build-ups. Mechanical
means to create movement within the fluid bed can be used as well, possibly in
intervals, in case that
the steam up flow from section B is not sufficient to prevent solidifications
area within the fluid bed 4
and remove build-ups (not shown). Solids can also be removed directly from 4,
from the fluid bed
section. The produced steam 1 from water flow 3 and from the driving super
heated steam 6 is used for
oil extraction or for other usages. In the case that the low quality water
feed 3 contains hydrocarbons,
portion of the hydrocarbons will be recovered with the produced steam and
injected into the
underground formation for heavy oil recovery. The produced steam 1 can be
further treated in
commercially available demister and gas-solids separator to remove water
droplets or flying solids
carried-on with the generated steam flow.
[39] FIGURE 31 is a steam drive direct contact steam generator apparatus.
Superheated
steam 7 is injected to a vertical enclosure at its lower section. Liquid water
3 is injected into the
enclosure above the steam injection area. The water injection can include
sprayer to disperse the water
and enhance the mixture between the liquid water 3 and the steam 7. The
injected water can be low
quality SAGD produced water, boiler blow-down, evaporator brine or water from
any other source, like
open mine tailings pond water. The injected water 3 can include dissolve or
suspended solids as well as
any other carbon or hydrocarbon contamination. To enhance the mixture of the
steam and the water
and to remove solids an internal structure 4 is placed in between the steam
injection section and the
water injection section. Internal 4 can include a moving bed or any other
configuration of free moving
elements, like chains 5 that can remove solids build-ups from the supplied
water 3. Mechanical energy
can be introduced into the internal structure 4 to generate continues or
interval movement between its
parts or between the internal structure to the enclosure. Vibration movement
can be introduced to the
bottom structure 6 to prevent solids build-ups. The solids 9 are collected and
removed from a cone 8 in
the enclosure bottom. One option is to generate a relative movement between
the upper bed structure
4 and the lower bed structure 6 and the enclosure wall. Any commercial
available design for a moving
bed internals can be used as well. The generated steam 2 is released from the
upper section of the
enclosure 2. The generated steam 1, can be further cleaned in a dry or wet
scrubber and used in
enhanced oil recovery by injection it underground, like in SAGD or CSS or to
heat water in an open mine
extraction process.
[40] FIGURE 3J is a steam drive direct contact steam generator with internal
wet scrubber
that generates additional wet solids free steam. Superheated steam 10 is
injected into section A of
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vertical enclosure. Liquid water 5 is injected and dispersed above the dry
steam injection point. A fluid
bed, possibly with additional solid particles 9 is supported above the steam
injection area 10 in section
A. The fluid bed is increasing the heat transfer between the up-flowing steam
10 and the dispersed
water 5. Solids 12 are remove from the bottom of section A for disposal or
further treatment. The
bottom section of the fluid bed can move by mechanical means to generate
moving or vibrating bed.
Solids can recover from the fluid bed at section A to maintain a constant
solids level. The up-flow
generated steam, possibly with solids particles, is flowing to section B. In
this section the up flowing
steam is scrubbed by liquid saturated water 7. To generate the contact between
the liquid saturated
water and the steam a liquid bath 7 can be used where the steam is forced (due
to pressure differences)
through the liquid water. Another option is to continually recycle hot
saturated liquid water 4 and spray
them at 2 into the up flowing steam, by that scrubbing any solids remains and
generating additional
steam. In Fig. J both options are presented (the liquid bath combined with the
water sprayers 2)
however it is possible to use only one of the presented options. If only
liquid bath 7 is used, the feed
water 3 will be supplied to the liquid bath as a make-up water (not shown) to
replace the water that was
evaporated in section B and water 5, with any solids scrubbed, from section B
that is supplied to section
A and evaporated there. The generated solids free saturated steam from section
B is flowing into section
C. Section C can include a demister to separate any droplets carried on with
the up-flow steam (not
shown). The produced solids free steam can be used for oilsands bitumen
recovery with any commercial
oilsands plant that required steam.
[411 FIGURE 3K is an illustration of one embodiment of the present invention.
An up-flow
direct contact steam generator, as described in Figure 3H or 31 is used to
generate steam 9 from
superheated steam and liquid water 8. Additional designs for direct contact
steam generators, like
Figure 2C, 2D and 2E can be used as well. The produced steam 9 is flowing to
an external wet scrubber
that also generates additional steam. The produced steam is mixed with liquid
water 11, possibly by
circulating system 12 with sprayers for dispersing the water 3, where any
solids remains are scrubbed
with the water droplets while wet steam is generated. Liquid water 8 at
saturate temperature and
pressure continually recycled and injected into the steam generator 2. Water
feed, possible with high
levels of contaminates, is feed into the system. Portion 14 from the produced
steam 13 is used for any
industrial usage, like for oil recover or for steam use in the chemical
industry. The other portion 15 of
the produced steam is recycled and used to produce dry superheated steam 24 to
operate the direct
contact steam generator 1. The recycled produced steam 15 can be further
filtered in any commercial
available filter packages to remove contaminates like gas silica remains.
Water and chemicals 17 can be
CA 02748477 2011-08-02
used in any gas treated commercial package 16. The steam 19 is then compressed
to recover the
pressure drops in the recycled piping and equipment and flow to steam heater.
Depend on the
mechanical compressing system 20 requirements, some heat can be added to flow
19 prior to the
compression. Another option is to use a steam ejector in 20 with high pressure
steam feed to generate
the recycle flow 21. The steam flow 21 is further heated in any commercial
available heating system 23.
Heat flow 22 increases the steam temperature 24 to generate a dry, superheated
steam flow that is
injected back to direct contact steam generator as the driving steam.
[42] FIGURE 4 is an illustration of one embodiment of the present invention,
where the
generated steam 44 is saturated and is washed by saturated water in a wet
scrubber 40 where
additional steam is generated. BLOCK 1 includes the system as described in
FIGURE 3 where BLOCK 32
can include solid removal as means to remove solid particles from the gas
(steam) flow. BLOCK 3
generates steam 33 and stable waste 35. The generated steam 33 can contain
carry-on solid particles
and contaminates that might create problems of corrosion or solids build ups
in the high temperature
heat exchanger. One way to remove the solid contaminates is by a commercially
available solid-gas
separation unit, as described in Figure 2B or with any other prior art solids
removal method. However,
there is an advantage to wet scrubbing of solids and possible other gas
contaminates. To improve the
removal of the solids and other contaminates, the steam 33 is directed to a
wet scrubber. In one
embodiment, the wet scrubber generates the liquid water for its operation.
This is done by an internal
heat exchanger that recovers heat from the steam and generates condensate
water. The condensate
liquid water is used for scrubbing the flowing steam in vessel 40. The
condensate is recycled 41 and used
to wash the steam and is used as a means to improve the heat transfer. Low
quality water from the oil-
water separation process, fine tailing water from tailing pond or from any
other source is pre-heated
through heat exchanger 42 while recovering heat from the produced steam 34
generated by the SD-
DCSG 30. The condensate is recycled in the wet scrubber to wash the steam.
Additional chemicals can
be added to the condensate to remove gas contaminates. A portion of the
condensate with the solids
and other contaminates 43 is removed from vessel 40 to maintain the
contamination concentration of
the condensate constant. Additional low quality water 47A can be added to the
SD-DCSG without pre-
heating as to prevent excessive cooling of the produced steam 33 and the
generation of excessive
condensate. The generated steam after going through the wet scrubber is clean
and saturated ("wet")
steam. A portion of the clean steam 45 is directed through trough heat
exchange 38 to generate "dry"
steam to drive the SD-DCSG 30 with sufficient thermal energy to convert the
low quality water feed 34
into steam. The flow through the heat exchanger and inside the vessel 30 is
generated by any suitable
CA 02748477 2011-08-02
commercial unit that can be driven by mechanical energy or a jet energy driven
compression unit. The
produced clean saturated steam 46 can be injected into an underground
reservoir, like SAGD, for oil
recovery, it can also be used for heating process water for tar separation or
for any other process that
consumes steam.
[43] FIGURE 5 is a schematic diagram of one embodiment of the invention that
generates
wet scrubbed, clean saturated steam. BLOCK 1 includes a SD-DCSG 30 as
previously described. The
generated steam 31 can be cleaned from solids in commercially unit 32,
previously described. Low
quality water 34, like MFT (Mature Fine Tailings), produced water or water
from any other available
source can be injected to the SD-DCSG 30. Solids 35 carried by the water 34
are removed. The SD-DCSG
30 is driven by superheated ("dry") steam that supplies the energy needed for
the steam generation
process. The dry steam 36 is generated by a commercially available boiler as
described in BLOCK 4. BFW
(Boiler Feed Water) 49 is supplied to BLOCK 4 for generating the driving
steam. The boiler facility can
include an industrial boiler, OTSG, COGEN combined with gas turbine, steam
turbine discharge re heater
or any other commercially available design that can generate dry steam 36 that
can drive the SD-DCSG
30. In the case where the boiler consumes low quality fuel, like petcoke or
coal, commercially available
flue gas treatment will be used. There is a lot of prior art knowledge as for
the facility in BLOCK 4 as it is
similar to the facility that is used all over the world for generating
electricity. The generated steam from
the SD-DCSG 37 is supplied to BLOCK 2 that includes a wet scrubber. The wet
scrubber 50 can contain
chemicals like ammonia or any other chemical additives to remove contaminates.
The exact chemicals
and their concentration will be determined based on the particular
contaminates in the low quality
water that is used. The contamination levels are much lower than in direct
fired DCSG where the water
is directly exposed to the combustion products as described in my previous
patents. Liquid water 48 is
injected to the wet scrubber vessel 50 to scrub the contaminates from the up-
flowing steam 37. Liquid
water 51 that includes the scrubbed solids are removed from vessel 50 and
recycled back to the SD-
DCSG 30 together with the feed water 34. Depending on the particular feed
water quality 34, it can be
used in the scrubber. In that case stream 48 and 34 will have the same
chemical properties and be from
the same source. The scrubbed generated steam 45 generated at BLOCK 2 can be
used for extracting
and producing of heavy oil or for any other use.
[44] FIGURE SA is an illustration of one embodiment of the invention where a
portion of the
driving steam water is internally generated. The embodiment is described in
Figure 5 with the following
changes: BLOCK 3 was added and connected to BLOCK 2. This block includes a
direct contact condenser /
heat exchanger 40 that is designed to generate hot (saturated) boiler feed
water 46 and possibly
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saturated steam 44. The saturated steam 45 from scrubber 50 flows into the
lower section of a direct
contact heat exchanger / condenser 40 where BFW 42 is injected. From the
direct contact during the
heat-up of the BFW, additional water will be condensed generating additional
BFW 46. A portion of the
injected and generated water 48 is used in wet scrubber 50 to remove
contamination and is then
recycled back to the SD-DCSG 30. The additional condensate, clean BFW quality
water 49, is used in
BLOCK 4 for generating steam. The condensate is hot at the water or steam
saturated temperature in
the particle system pressure. Addition hot condensate can be generated and
recovered from the system
as hot process water for oil recovery or for other uses. BLOCK 4 can include
any commercially available
steam generator boiler capable of producing dry steam 36. In Figure 5A a
schematic COGEN is described.
Gas turbine 62 generates electricity. The gas turbine flue gas heat is used to
generate or heat steam
through non-direct heat exchanger 61. Typically the produced steam is used to
operate steam turbines
as part from a combined cycle. At least part of the produces dry superheated
steam 36 is used to
operate the SD-DCSG 30.
[45] FIGURE 5B is a schematic view of the invention with internal distillation
water
production for the boiler. The illustration is similar to the process
described in Figure 5A with a different
BLOCK 3. The low quality water 47 is heated with the saturated clean (wet
scrubbed) steam 45 from
BLOCK 2 (previously described). The saturated steam 45 condenses on the heat
exchanger 42, located
inside vessel 40, while generating distilled water 46. A portion of the
distilled water 48 is recycled to the
wet scrubber vessel 50 where it removes the solids and generates additional
wet steam from the
partially dry steam generated in the SD-DCSG 30 in BLOCK 1. Additional
distilled water 49, possibly after
minor treatment and chemical additives (not shown) to bring it to BFW
specifications, is directed to the
boiler in BLOCK 4 for generating the driving steam. The system can produce
saturated steam 44A or
saturated liquid distilled water 44B or both. The produced steam and water are
used for oil production
and process or for any other use.
[46] FIGURE 5C is a schematic diagram of the method that is similar to Figure
5B but with a
different type of SD-DCSG in Block 1. Figure 5C includes a vertical stationary
SD-DCSG. The dry driving
steam 36 is fed into vessel 30 where the low quality water 34 is fed above it.
Due to excessive heat, the
liquid water is converted into steam. The waste discharge at the bottom 35 can
be in a liquid or solid
form. BLOCKS 2, 3 and 4 are similar to the previous Figure 5B.
[47] FIGURE 6 is a schematic diagram of the present invention which includes a
SD-DCSG and
an FOR facility like SAGD for injecting steam underground. BLOCK 1 is a
standard commercially available
boiler facility. Fuel 1 and oxidizer 2 are combusted in the boiler 3. The
combustion heat is recovered
CA 02748477 2011-08-02
through non-direct steam generator for generation of superheated dry steam 9.
The combustion gases
are released to the atmosphere or for further treatment (like solid particles
removal, SOX removal, CO2
recovery etc.). The water that is fed to the boiler, is fed from BLOCK 2 which
includes a commercially
available boiler treatment facility. The quality of the supplied water is
according the particular
specifications of the steam generation system in use. The dry steam is fed to
SD-DCSG 10. Additional low
quality water 7 is fed into vessel 11 where the liquid water is transferred to
steam due to the excess
heat in the superheated driving steam 9. The generated steam 8, possibly
saturated or close to being
saturated steam, is injected into an underground formation through an
injection well 16 for EOR. The
produced emulsion 13 of water and bitumen is recovered at the production well
15. The produced
emulsion is treated using commercially available technology and facilities in
BLOCK 2, where the
bitumen is recovered and the water is treated for re-use as a BFW. Additional
make-up water 14,
possibly from water wells or from any other available water source can be
added and treated in the
water treatment plant. The water treatment plant produces two streams of water
- a BFW quality 6
stream as it is currently done to feed the boilers and another stream of
contaminated water 7 that can
include the chemicals that were used to produced the high quality BFW, oil
contaminates, dissolved
solid (like salts) and suspended solids (like silica and clay). The low
quality flow is fed to the SD-DCSG 10
to generate injection steam.
[48] FIGURE 6A is a schematic flow diagram of the integration between SD-DCSG
and DCSG
that uses the combustion gas generated by pressurized boiler. BLOCK 1 includes
a DCSG with non-direct
heat exchanger boiler as described in my previous applications. Carbon or
hydrocarbon fuel 2 is mixed
with an oxidizer that can be air, oxygen or oxygen enriched air 1 and
combusted in a pressurized
combustor. Low quality water 12 discharged from the SD-DCSG is fed into the
combustion unit to
recover a portion of the combustion heat and to generate a stream of steam and
combustion gas
mixture 4. The solid contaminates 18 are removed in a solid or stable slurry
form where they can be
disposed of. The steam and combustion gas mixture 4 is injected into injection
well 17 for EOR. Injection
well 17 can be a SAGD "old" injection well where the formation oil is partly
recovered and large
underground volumes are available, as well as where corrosion problems are not
so crucial as the well is
approaching the end of its service life. Another preferable option for using
the steam and combustion
gas mixture is to inject it into a formation that is losing pressure and needs
to be pressurized by the
injection of addition non-condensable gas, together with the steam. A portion
of the combustion
energy is used to generate superheated dry steam in a boiler type heat
exchanger 5. The generated
steam 9 is driving the SD-DCSG 10. The water for the non-direct boiler 5 is
supplied from the
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commercially available water treatment plant in BLOCK 2. Low quality water
from BLOCK 2 is fed directly
into the SD-DCSG where it is converted into steam. In this scheme, the
conversion is only partial as the
discharge from 10 is in a liquid form 12. The liquid discharge 12 is directed
to the combustion DCSG to
generate an overall ZLD (Zero Liquid Discharge) facility. The steam from the
SD-DCSG 8 is injected into
an underground formation through an injection well 16 for EOR.
[49] FIGURE 6B described a direct contact steam generator with rotating
internals, dry solids
separation and wet scrubber and saturated steam generator. Super heated
driving steam 13 is fed into
a direct contact steam generator where it is mixed with water, possibly with
contaminates. The
excessive heat energy in the steam evaporates the water to generate additional
steam. Solids 6 are
removed from the system in dry or slurry form. The produced steam is treated
in commercial available
gas treatment unit in block B. An inlet demister to removed carried-on liquid
droplets can be
incorporated in block B. Any commercial available unit to remove solids and
contaminates can be used
like cyclone solid removal system as schematically described in B1, a high
temperature filter B2, an
electrostatic precipitator 83 or combination with any other commercial
available design. The solids
removed in a dry form are added to the solids removed from the steam generator
14. The solids lean
flow 5 is fed into a saturated steam generator and a wet scrubber 2. Liquid
water recycled and dispersed
into the flowing steam. Portion from liquid water evaporates. The water
droplets remove contaminates.
Chemicals like anti-foaming, flocculants, Ph control and other commercial
available chemicals to control
the process efficiency and prevent corrosion can be added to the recycled
water 11. Make-up water 10
can be added to the system to replace the water converted to steam and the
recycled water with the
contaminates back to the feed water 13. The scrubbed solids free generated
steam 8 is supplied from
the system for other usages.
[50] FIGURE 6C includes SD-DCSG and heavy oil extraction through steam
injection. Emulsion
of steam, water bitumen and gas is produced from a production well 10, like a
SAGD well. The produced
flow 1 is separated in a separator 3 located in BLOCK A to generate water rich
flow 5 with contaminates
like sand, and hydrocarbons rich flow 4. There are few commercial designs for
separators that are
currently used by the industry. Chemicals can be added to the separation
process. The hydrocarbon rich
flow 4 is further treated in processing plant at BLOCK B. Flow 4 is furthered
separated into the produced
bitumen, usually diluted with light hydrocarbons to enhance the separation
process and to reduce the
viscosity to allow the flow of the bitumen in the transportation lines. In
block B the produced water that
remained with the flow 4 are de-oiled and used, usually with make-up water
from water wells, for
generated super-heated steam 6. The water rich flow 5, at a high temperature
that is close to the
CA 02748477 2011-08-02
produced emulsion temperature, is pumped into a SD-DCSG 7 where it is mixed
with the dry
superheated steam 6 to generate additional steam for injection 2. Light
hydrocarbons in flow 5
evaporate due to the heat to generate hydrocarbons that are injected with the
injection steam 2 to the
underground formation 11. It is known that hydrocarbons that are mixed with
the steam can improve
the oil recovery. The SD-DCSG 7 includes a rotating internals to enhance the
mixture between the two
phases and mobilized the generate slurry and solids. The solids 8 removed from
the system for landfill
disposal 13 or for any other use. The heat energy within flow 5 from separator
3 increase the quantity of
the steam generated in SD- DCSG 7 and by that improves the overall thermal
efficiency of the system.
The generated steam 2 is injected, possibly after additional contaminate
removal treatment and
pressure control (not shown), into an injection well 11 for EOR. The SD-DCSG 7
is a parallel flow steam
generator as described by unit 1 in figure 3E, however any other SD-DCSG
design like the counter flow
SD-DCSG as described by unit 15 in figure 3E, the rotating or fluid bed units
as described in drawings 2C,
2D and 3C-3J can be used as well.
[511 FIGURE 6D includes SD-DCSG similar to the system in 6C, where the
superheated driving
steam is generated by recycling and re-heating the produced steam generated by
the SD-DCSG 7. A
mixture of steam, water, bitumen and gas is produced from a production well
10, like a SAGD well. The
produced flow 1 is separated in a separator 3 located in BLOCK A to generate
water rich flow 5 and
hydrocarbons rich flow 4. There are few commercial design for separators that
are currently used by the
industry. Chemicals can be added to the separation process. The hydrocarbon
rich flow is further
treated in processing plant at BLOCK B. The water rich flow 5, possibly with
hydrocarbons and other
contaminates like sand is at a high temperature that is close to the produced
emulsion temperature. The
heat energy within flow 5 increase the quantity of the steam generated in SD-
DCSG 7 for a given
amount of superheated driving steam 6. Flow 5 is pumped into a SD-DCSG 7 where
it is mixed with dry
superheated steam 6 to generate additional steam 18. Any available design for
mixing the water and the
steam to generate additional steam and solids or slurry discharge can be used
as well. The solids or
slurry 8 removed from the system for landfill disposal 13 or for any other
use. The produced steam 18 is
split into two flows - flow 2 of the generated steam 18 is injected, possibly
after additional contaminate
removal treatment and pressure control (not shown), into an injection well 11
for EOR. The other part
from flow 18, flow 12, is recycled to BLOCK C. Depending on the recycled steam
quality and the feed
requirements of the compressing and heating units, it can be pre-cleaned by
any commercial available
cleaning technologies. The recycled produce steam is compressed by mechanical
compressor, steam
ejector or any other available units 14 and indirectly heated by heat flow 15
to generate a super heated
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driving steam flow 6. The heating can be done with any available heating unit
that can heat steam,
possibly with hydrocarbons remains. Electrical heaters for small units, carbon
(like coal, petcoke etc')
combustion units for large scale or hydrocarbon fired (like natural or
produced gas, bitumen etc') for
medium and large size units can be used as facility 16 for heating the
produced steam (possibly with
small amounts of hydrocarbon gas) to generate the dry, superheated driving
steam 6. The superheated
driving steam 6 is injected to the SD-DCSG 7 where it is mixed with the
produced water 5.
[52] FIGURE 6E is a schematic view of SD-DCSG with similarities to figure 6D
and with
external supplied make-up HP steam. A mixture of steam, water, bitumen and gas
is produced from a
production well 10, like a SAGD well. The produced flow 1 is separated in a
separator 3 located in BLOCK
A to generate water rich flow 5 and hydrocarbons rich flow 4. There are few
commercial designs for
separators that can be used. Chemicals can be added to the separation process.
The hydrocarbon rich
flow is further treated in commercial available oil and water processing plant
at BLOCK B. There are
commercial available technologies and designs for such plants where some are
used by the oilsands
thermal insitue industry (like SAGD processing plant). The water rich flow 5,
possibly with hydrocarbons
and other contaminates like sand is at a high temperature close to the
produced emulsion 1
temperature. Flow 5 is pumped into a SD-DCSG 7 where it is mixed with dry
superheated steam 6 to
generate additional steam 18. The SD-DCSG is a counter flow design as
described by unit 15 at figure 3E.
Any available design for mixing the water and the steam to generate additional
steam and solids rich
water can be used as well. The solids or slurry removed from the system
through separator 20 and de-
compression system 21 in a stable form 22. The produced steam 18 is split into
two flows - flow 2 of
the generated steam 18 is injected, possibly after additional contaminate
removal treatment and
pressure control (not shown), into an injection well 11 for FOR or for any
other usage in the mining or
any other industry that required large quantities of steam. The other part
from flow 18, flow 12, is
recycled to re-heat and use as the superheated driving steam. In non-direct
contact heater 16,
additional heat Q is added to the steam flow 12 to generate superheated dry
steam 13. The heating can
be done with any available heating facility. This superheated steam is
compressed with the pressure
energy from HP (High Pressure) make-up steam 6 generated in BLOCK B. The make
up steam is produced
from the produced water that remains in flow 4. The produced water is treated
in the process facility in
BLOCK B that includes de-oiled and possibly de-mineralized before used in
commercial available high
pressure boiler or OTSG for generating high pressure steam 6. Additional make-
up water 24 is usually
required to compensate for the water loss in the formation and for the waste
water rejected from the
water treatment facility in BLOCK B. The make-up water is usually supplied
from water well 25 or from
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any available water source. Disposal water 23 from the water processing
facility in BLOCK B, possibly
with oil and solids can be recycled to the SD-DCSG 7 together with stream 5 as
the water feed to 7.
[53] FIGURE 6F describes another embodiment of the present invention for
generating
steam for oil extraction with the use of steam boiler and steam heater. A
mixture 36 of steam, water,
bitumen and gas is produced from a production well 32, like a SAGD production
well. The produced flow
36 is separated in a separator 33 to separate the produced gas 38 from the
produced liquids 37. The
produced gas 38 can include reservoir gas, mainly light hydrocarbons and
possibly lifting gas, in case
lifting gas is used to lift the produced liquids to the surface (not shown).
The produced gas is used in the
process as lifting gas. It can also used as fuel for the boilers or for any
other used. The produced liquid
emulsion 37 is cooled in heat exchanger 34 while heating the boiler feed water
40 to generate pre-
heated boiler feed water. The cooled liquid mixture 39, after the produced gas
were already removed is
feed into separator 35. Chemicals, sometime with solvents like light
hydrocarbons, can be added to the
produced liquid 39 to support the separation process, break the emulsion and
prevent foaming. The
separation vessel 35 separates the water liquid 43 from the bitumen 41. The
separation process is a well
known process with the heavy oil industry. The gas separator reactor 33 and
the water-oil separator
reactor 35 are commercial available units. Any additional configuration to
enhance the gas-water-oil
separation can be used as well. The produce oil 41 is further treated in a
commercially available process
area BLOCK 1 commonly used with the insitue thermal oil recovery industry,
like SAGD or CSS. Solvents
can be added to the produced bitumen 41 to remove the water remains and other
contaminates. BLOCK
A includes commercial available water treatment facility, like evaporators, to
generate boiler feed water
quality water 40. The water feed to the water treatment plant in BLOCK 1 can
be from the water
remains in flow 41. Additional water can be directed to the water treatment
plant from water 43 that
was separated in vessel 35. The produced water used as feed to the boiler feed
water treatment plant is
de-oiled to remove oil traces that can impact the water treatment process in
BLOCK 1. Additional make-
up water can be added to the process in block 1 from any other water source,
like water wells. Usually
the make-up water do not include organic contaminates so it is easier to treat
them with evaporators
and other commercially available distillation units. (See Society of Petroleum
Engineers paper no
137633-MS Titled "Integrated Steam Generation Process and System for Enhanced
Oil Recovery"
presented by M. Betzer at the Canadian Unconventional Resources and
International Petroleum
Conference, 19-21 October 2010, Calgary, Alberta, Canada.) The produced water
flow 7, possibly with
solids contaminates and oil remains are mix with superheated steam 6. Due to
the contaminated within
the produce water feed 7 a rotating internal 2 is used to enhance the mixture
and remove build-ups
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within enclosure 1. Due to the driving steam 6 high temperatures (compared to
the saturated steam
temperature at the system pressure), liquid water from Flow 7 is converted to
steam. The amount of
water converted is a function of the ratio of the driving steam 6 and the
liquid water 7. If disposal wells
are available, it is possible to convert only portion of the water into steam
and disposed the remaining
water with the contaminated solids 12 into a disposal well 13. Heat can be
recovered from the disposal
liquid flow 12 through heat exchanger (not shown). The produced steam 20 is
separated from the
disposal flow 12 or 15 in a separation enclosure 10. If disposal wells for
disposing fluids are not available,
or ZLD facility is preferred, most of the water 7 can be converted to steam
generating solids or stable
slurry 15 for landfill disposal 16 or further treatment. The produced steam
flow 20 is used for injection
for thermal oil recovery through an injection well. Portion 21 of the produced
steam 20 is used to
generate the driving superheated steams 6. The clean BFW (Boiler Feed Water)
28 is used for generating
steam through commercial boiler or OTSG that include heat exchanger 26 to
generate High Pressure
steam 24. Any type of commercial available boiler and a steam separation
vessel can be used. The
produced HP steam 24 is used to recycle steam 21 to heater 27 to generate
superheated dry steam
stream 6 to drive the steam generation process at 1. The pumping and
circulating of the produced steam
21 is done through steam ejector 23 that use the pressure of the HP steam as
the energy source to
compress and circulate portion 21 of the produced steam 20 through the heat
exchanger 27. As
described the produced steam 21 can be further treated in a separate unit to
remove contaminates
from the produced steam flow, like silica, that can affect the super heater
heat exchanger 27
performance and create deposits. There are few technologies that can be used.
One option is to use a
liquid scrubber with saturated liquid water, possibly with chemicals, to
remove contaminates that can
affect the performance of the non-direct heat exchanger 27, or in some cases
the steam lines and the
injection well 31. Other technological solution to remove the undesired
contaminates from the steam
gas flow can be used as well. The feed water 40 is a treated water with low
level of contaminates as
required by ASME specifications for boiler feed water. There is a lot of
knowledge and commercial
available packages to generate the BFW 40 used for generated the high pressure
steam 24. In the
current sketch the boiler integrate the steam generation section 26 and the re-
heater section 27 for
generating super-heated driving steam 6 from the produced steam 21 and the
high pressure driving
steam 24 for operate ejector and as a driving steam. It is possible to
separate the production of the high
pressure steam 24 from the superheated steam into two separate units while the
steam 24 is generated
through package boiler, OTSG or any other type of commercially available
boiler, with any type of
carbon or hydrocarbon fuel. The produced steam 21 is heated to generate
superheated drive steam with
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any commercially available heat exchanger design. The heater can be integrated
into the boiler or a
separate unit with any available hearer design.
[54] FIGURE 7 is a schematic view of an integrated facility of the present
invention with a
commercially available steam generation facility and FOR for heavy oil
production. The steam for FOR is
generated using a lime softener based water treatment plant and OTSG steam
generation facility. This
type of configuration is most common in FOR facilities in Alberta. It recovers
bitumen from deep oil sand
formations using SAGD, CSS etc. Produced emulsion 3 from the production well
54, is separated inside
the separator facility to bitumen 4 and water 5. There are many methods from
separating the bitumen
from the water. The most common one uses gravity. Light hydrocarbons can be
added to the product to
improve the separation process. The water, with some oil remnants, flows to a
produced water de-oiling
facility 6. In this facility, de-oiling polymers are added. Waste water, with
oil and solids, is rejected from
the de-oiling facility 6. In a traditional system, the waste water would be
recycled or disposed of in deep
injection wells. The de-oiled water 10 is injected into a warm or hot lime
softener 12, where lime,
magnesium oxide and other softening chemicals are added 8. The softener
generates sludge 13. In a
standard facility, the sludge is disposed of in a landfill. The sludge is semi-
wet, and hard to stabilize. The
softened water 14 flows to a filter 15 where filter waste is generated 16. The
waste is sent to an ion-
exchange package 19, where regeneration chemicals 18 are continually used and
rejected with carry-on
water as waste 20. In a standard system, the treated water 21 flows to an OTSG
where approximately
80% quality steam is generated 27. The OTSG typically uses natural gas 25 and
air 26 to generate steam.
The flue gas is released to the atmosphere through a stack 24. Its saturated
steam pressure is around
100bar and the temperature is slightly greater than 300C. In a standard SAGD
system the steam is
separated in a separator, to generate 100% steam 29 for FOR and blow-down
water. The blow down
water can be used as a heat source and also to generate low pressure steam.
The steam, 29 is delivered
to pads, where it is processed and injected into the ground through an
injection well 53. In the current
method, additional dry superheated steam flow is produced to drive the SD-DCSG
in BLOCK 1 to
generate additional injection steam from the waste water stream. The
production well 54, located in
the FOR field facilities BLOCK 4, produces an emulsion of water and bitumen 3.
In some FOR facilities,
injection and production occur in the same well, where the steam can be 80%
quality steam 27. The
steam is then injected into the well with the water. This is typical of the
CSS pads where wells 53 and 54
are basically the same well. The reject streams include the blow down water
from OTSG 23, as well as
the oily waste water, solids and polymer remnants from the produced water de-
oiling unit. This also
includes sludge 13 from the lime softener, filtrate waste 16 from the filters
and regeneration waste from
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the Ion-Exchange system 20. The reject streams are collected 33 and injected
directly 33A into Steam
Drive Direct Contact Steam Generation 30 in BLOCK 1. The SD-DCSG can be
vertical, stationary,
horizontal or rotating. Dry solids 35 are discharged from the SD-DCSG, after
most of the liquid water is
converted to steam. The SD-DCSG generated steam 31 temperatures can vary
between 120C and 300C.
The pressure can vary between lbar and 50 bar. The produced steam 32 can be
injected directly 45A
into the injection well 53, possibly after additional solids and contamination
removal in BLOCK 32.
Another option is to wash the generated steam in wet scrubber 50 in BLOCK 2.
BLOCK 2 is optional and
can be bypassed by flows 33A and 45A. The produced steam from the SD-DCSG 31
is injected into a
scrubber vessel 50 where the steam gas is washed with saturated water 48 that
was condensed from
the produced gas 31 or from additional liquid water supplied to the wet
scrubber vessel 50 to remove
the solid remnants and possibly chemical contaminates. Solid rich water 51 is
continually removed from
the bottom of vessel 50. It is recycled back to the SD-DCSG, where the solids
are removed in dry or semi-
dry form 35. The liquid water is converted back to steam 31. The saturated
wash water in vessel 50 is
generated by removing heat through non-direct heat exchange with the feed
water 33. A portion of the
steam condenses to generate washing liquid water at vessel 50. The liquid
water continually recycled to
enhance the washing and the wet scrubbing. The SD-DCSG is driven by
superheated steam generated by
the steam generator 23 or in a separate boiler or in a separate heat exchanger
within the boiler (re-
heater type heat is exchanged to heat steam to produce a superheated steam).
There are many varieties
of commercially available options to generate the dry steam needed to drive
the process in the SD-
DCSG. The generated clean steam 45 is injected into an underground formation
for EOR.
[55] FIGURE 8 is a schematic of the invention with an open mine oilsand
extraction facility, where
the hot process water for the ore preparation is generated from condensing the
steam produced from
the fine tailings using a SD-DCSG. A typical mine and extraction facility is
briefly described in BLOCK 5.
The tailing water 27 from the oilsand mine facility is disposed of in a
tailing pond. The tailing ponds are
built in such a way that the sand tailings are used to build the containment
areas for the fine tailings.
The tailing sources come from Extraction Process. They include the cyclone
underflow tailings 13, mainly
coarse tailings, and the fine tailings from the thickener 18, where
flocculants are added to enhance the
solid settling and recycling of warm water. Another source of fine tailings is
the Froth Treatment
Tailings, where the tailings are discarded using the solvent recovery process-
characterized by high fines
content, relatively high asphaltene content, and residual solvent. (See "Past,
Present and Future Tailings,
Tailing Experience at Albian Sands Energy" a presentation by Jonathan Matthews
from Shell Canada
Energy on December 8, 2008 at the International Oil Sands Tailings Conference
in Edmonton, Alberta). A
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sand dyke 55 contains a tailing pond. The sand separates from the tailings and
generates a sand beach
56. Fine tailings 57 are put above the sand beach at the middle-low section of
the tailing pond. Some
fine tailings are trapped in the sand beach 56. On top of the fine tailing is
the recycled water layer 58.
The tailing concentration increases with depth. Close to the bottom of the
tailing layer are the MFT
(Mature Fine Tailings). (See "The Chemistry of Oil Sands Tailings: Production
to Treatment" presentation
by R.J. Mikula, V.A. Munoz, O.E. Omotoso, and K.L. Kasperski of CanmetENERGY,
Devon, Alberta, Natural
Resources Canada on December 8, 2008 at the International Oil Sands Tailings
Conference in Edmonton,
Alberta). The recycled water 41 is pumped from a location close to the surface
of the tailing pond
(typically from a floating barge). The fine tailings that are used for
generating steam and solid waste in
this invention are the MFT. They are pumped from the deep areas of the fine
tailings 43. MFT 43 is
pumped from the lower section of the tailing pond and is then directed to the
SD-DCSG in BLOCK 1 and
in BLOCK 3. The SD-DCSG that includes BLOCKS 1-4 is described in Figure 5B.
However, any available SD-
DCSG that can generate gas and solids from the MFT can be used as well. Due to
the heat from the
superheated steam and pressure inside the SD-DCSG, the MFT turns into gas and
solids as the water is
converted to steam. The solids are recovered in a dry form or in a semi-dry,
semi-solid slurry form. The
semi-dry slurry form is stable enough to be sent back into the oilsand mine
without the need for further
drying to support traffic. The produced steam needed for extraction and froth
treatment, is generated
by a standard steam generation facility 61 used to generate the driving steam
for the DCSG in BLOCK 1
or from the steam produced from the SD-DCSG 62. The generated saturated steam
47 is mixed with the
process water 41 in mixing enclosure 45 to generate the hot water 52 used in
the extraction process in
BLOCK 5. By continually consuming the fine tailing water 43, the oil sand mine
facility can use a much
smaller tailing pond as a means of separating the recycled water from the fine
tailings. This solution will
allow for the creation of a sustainable, fully recyclable water solution for
the open mine oilsand
facilities.
[56] FIGURE 9 is a schematic view of the invention with an open mine oilsand
extraction facility
and a prior art commercially available pressurized fluid bed boiler that uses
combustion coal for
power supply. Examples of pressurized boilers are the Pressurized Internally
Circulating Fluidized-
bed Boiler (PICFB) developed and tested by Ebara, and the Pressurized-Fluid -
Bed-Combustion-
Boiler (PFBC) developed by Babcock-Hitachi. Any other pressurized combustion
boiler that can
combust petcoke or coal can be used as well. BLOCK 1 is a prior art
Pressurized Boiler. Air 64 is
compressed 57 and supplied to the bottom of the fluid bed combustor to support
the combustion.
Fuel 60, like petcoke, is crushed and grinded, possibly with lime stone 61 and
water 62, to generate
CA 02748477 2011-08-02
pumpable slurry 59. Water 62 is recycled water with high level of contaminates
38, as discharged
from the SD-DCSG 28. Some portion or stream 38A can be injected above the
combustion area to
directly recover heat from the combustion gas to generate steam. The boiler
includes an internal
heat exchanger 63 to generate high pressure steam 51 to drive the SD-DCSG. The
steam 51 is
generated from steam boiler drum 52 with boiler water circulation pump 58. The
boiler heat
exchanger 63 recovers energy from the combustion. BFW 37 is fed to the boiler
to generate steam
51. The steam can be heated again in a boiler heat exchanger (not shown) to
generate a
superheated steam stream. The steam used to drive the SD-DCSG 28. The boiler
generates
pressurized combustion gas and steam mixture 1 from the SD-DCSG discharged
water 24 at a
pressure of 103kpa and up to 1.5Mpa and temperatures of 2000-9000. The
discharge flow is treated
in BLOCK 3 to generate a steam and combustion gas mixture for EOR. The mixture
8 is injected into
an underground formation through an injection well 7. There is no need to
remove solids from the
combustion gas 1 because this gas is fed to the DCSG in Block 3 that works as
a wet scrubber and
remove solids and possibly contaminated gas like SOx and NOx while creating a
steam and
combustion gas mixture. Solids from the fluid bed of the PFBC 55 can be
recovered to maintain the
fluid bed solids level. (This is a common practice in FBC (Fluid Bed
Combustion) and PFBC). The fluid
bed solids can be mixed with the DCSG solids from BLOCK 3 (not shown). The
pressurized
combustion gases leaving AREA#1 are mixed with the concentrate effluent from
SD-DCSG 28 and
possibly with other low quality waste water and slurry sources, like HLS/WLS
sludge produced by
SAGD/CSS water treatment plant (not shown). Block 2 includes a commercially
available FOR facility,
like SAGD, where the water and bitumen emulsion is treated to generate BFW
water quality and low
quality water that is fed into the SD-DCSG. There will be two types of
injection wells - for the
injection of pure steam from the SD-DCSG 6 and for the injection of a mixture
of steam and
combustion gases, mainly CO2 7. It is possible to combine the two types of FOR
fluids in one
production facility where the aging injection wells will be converted from
pure steam to a steam and
combustion gas mixture to pressurize the underground formation and increase
the bitumen
recovery due to the CO2 dissolved that increases the bitumen fluidity.
[57] FIGURE 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG.
Fuel 2 is
mixed with air 55 and injected into a Pressurized Fluidized-Bed Boiler 51. The
fuel 2 can be generated
from the water-bitumen separation process and includes reject bitumen slurry,
possibly with chemicals
that were used during the separation process and sand and clay remains.
Additional low quality carbon
fuel can be added to the slurry. This carbon or hydrocarbon fuel can include
coal, petcoke, asphaltin or
CA 02748477 2011-08-02
any other available fuel. Lime stone can be added to the fuel 2 or to the
water 52 to remove acid gases
like SOx. The Fluidized-Bed boiler is modified with water injection 52 to
convert it to a DCSG. It includes
reduced capacity internal heat exchangers to recover less combustion heat. The
reduction in the heat
exchanger required capacity is because more combustion energy will be consumed
due to the direct
heat exchange with the water within the fuel slurry 2 and the additional
injected solid rich water 52
leaving less available heat to generate high pressure steam through the boiler
heat exchangers 56. The
boiler produces high-pressure steam 59 from distilled, de-mineralized feed
water 37. The produced
steam 59, or part of it 31, can be re-heated in re-heater 56 to generate super
heated seam 32 to operate
the SD-DCSG in BLOCK 3. There are several pressurized boiler designs for BLOCK
1 that can be modified
with direct water injections. One example of such a design is the EBARA Corp.
PICFB (see paper No.
FBC99-0031 Status of Pressurized Internally Circulating Fluidized-Bed Gasifier
(PICFG) development
Project dated May-16-19, 1999 and US RE37,300 E issued to Nagato et al on July
31, 2001). Any other
commercially available Pressurized Fluidized Bed Combustion (PFBC) can be used
as well. Another
modification to the fluid bed boiler can be reducing the boiler combustion
pressure down to 102kpa.
This will reduce the plant TIC (Total Installed Cost) and the pumps and
compressors' energy
consumption. The superheated steam 32 is supplied to BLOCK 3 where it is used
by the SD-DCSG 28 for
generating additional steam from low quality water. BLOCK 2 includes a water
treatment facility as
previously described. The steam and combustion gas mixture stream 1 is
supplied to BLOCK 2 where the
water and heat can be used for generating clean BFW by evaporation /
distillation facility. The pressure
energy in flow 1 can be used to separate CO2 from the NCG using commercially
available membrane
technologies. The combustion oxidizer, like air, 55 is injected at the bottom
of the boiler to maintain the
fluidized bed. High pressure 100% quality steam 59 is generated from distilled
water 37 through heat
exchange inside the boiler 51. The generated steam 59 can be further heated in
heat exchanger 56 to
generate super-heated steam 32 that is used in BLOCK 3 as the driving steam
for the SD-DCSG 28. The
steam generated in BLOCK 3 is injected, through an injection well 16, into an
underground formation for
EOR. Hydrocarbons and water 13 are produced from the production well 15. The
mixture is separated in
a commercially available separation facility in BLOCK 2.
[58] FIGURE 11 is a schematic diagram of the present invention which includes
a steam
generation facility, SD-DCSG, a fired DCSG and MED water treatment plant.
BLOCK 1 is a standard,
commercially available steam generation facility that includes an atmospheric
steam boiler or OTSG 7.
Fuel 1 and air 2 are combusted under atmospheric pressure conditions. The
discharged heat is used to
generate steam 5 from de-mineralized distilled water 29. The combustion gas is
discharged through
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stack 3. The generated steam is supplied to SD-DCSG 11 in BLOCK 4 that
generates additional steam
from the concentrated brine 38 discharged from the MED in BLOCK 2. The
generated steam 8 is injected
into an underground formation 6. The liquid discharge 14 from SD-DCSG 11 is
injected into an internally
fired DCSG 15 in BLOCK 3. Carbon fuel 41, like petcoke or coal slurry, is
mixed with oxygen-rich gas 42
and combusted in a DCSG 15. Discharged liquids from the SD-DCSG 11 are mixed
with the pressurized
combustion gas to generate a stream of steam-rich gas and solids 13. To reduce
the amount of SO2,
limestone can be added to the brine water 14 or to the fuel 41 injected into
the DCSG, to react with the
SO2. The solids are separated in separator 16. The separated solids 17 are
discharged in a dry form from
the solids separator 16 for disposal. The steam and combustion gas 12 flows to
heat exchanger 25 and
condenser 28. The steam in gas flow 12 is condensed to generate condensate 24.
The condensate is
treated (not shown) to remove contaminants and generate BFW that is added to
the distillate BFW 29
then supplied to the steam generation facility. The NCG (Non-Condensation Gas)
40 is released to the
atmosphere or used for further recovery, like CO2 extraction. The heat
recovered in heat exchanger 28
is used to generate steam to operate the MED 30 (a commercially available
package). The water 1 fed to
the MED is de-oiled produced water, possibly with make-up underground brackish
water. The Multi
Effect Distillation takes place in a series of vessels (effects) 31 and uses
the principles of condensation
and evaporation at a reduced pressure. The heat is supplied to the first
effect 31 in the form of steam
26. The steam 26 is injected into the first effect 31 at a pressure of 0.2bar
to 12 bar. The steam
condenses while feed water 32 is heated. The condensation 34 is collected and
used for boiler feed
water 37. Each effect consists of a vessel 31, a heat exchanger, and flow
connections, 35. There are
several commercial designs available for the heat exchanger area: horizontal
tubes with a falling brine
film, vertical tubes with a rising liquid, a falling film, or plates with a
falling film. The feed water 32 is
distributed on the surfaces of the heat exchanger and the evaporator. The
steam produced in each
effect condenses on the colder heat transfer surface of the next effect. The
last effect 39 consists of the
final condenser, which is continually cooled by the feed water, thus
preheating the feed water 1. To
improve the condensing recovery, the feed water can be cooled by air coolers
before being introduced
into the MED (not shown). The feed water may come from de-oiled produced
water, brackish water,
water wells or from any other locally available water source. The brine
concentrate 2 is recycled back, to
the SD-DCSG in BLOCK 4.
[59] FIGURE 11A is a view of the present invention that includes a steam
generation facility,
SD-DCSG and MED water treatment plant. BLOCK 1 is a standard, commercially
available steam
generation facility for generating super heated driving steam 5. The driving
steam 5 is fed to SD-DCSG in
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BLOCK 3. Discharged brine from the commercial MED facility in BLOCK 2 is also
injected to the SD-DCSG
15 and converted to steam and solid particles 13. The solids 17 are removed
for disposal. A portion of
the generated steam 12 is used to operate the MED through heat exchanger /
condenser 28. The
condensate 24, after further treatment (not shown), is used as BFW. The MED
produces distilled BFW 29
that is used to produce the driving steam at the boiler 7. The steam 8 is
injected through injection well 6
for EOR.
[60] FIGURE 11B is a schematic diagram of the present invention that includes
a steam drive
DCSG with a direct heated MSF (Multi Stage Flash) water treatment plant and a
steam boiler for
generating steam for EOR. Block 4 includes a commercially available steam
generation facility. Fuel 2 is
mixed with oxidized gas 1 and injected into the steam boiler (a commercially
available atmospheric
pressure boiler). If a solid-fuel boiler is used, the boiler might include a
solid waste discharge. The boiler
produces high-pressure steam 5 from distilled BFW 39. The steam is injected
into the underground
formation through injection well 6 for EOR. Portion of the steam can be used
to operate the DCSG. The
boiler combustion gas may be cleaned and discharged from stack 3. If natural
gas is used as the fuel 2,
there is currently no mandatory requirement in Alberta for further treatment
of the discharged flue gas
or for removal of CO2. Steam 9 injected into a pressurized DCSG 15 at an
elevated pressure. The DCSG
design can be a horizontal sloped rotating reactor, however any other reactor
that can generate a
stream of stean and solids can also be used. Solids - rich water 14 that
includes the brine from the MSF,
is injected into the direct contact steam generator 15 where the water
evaporates into steam and the
solids are carried on with gas flow 13. The amount of water 14 is controlled
to verify that all the water is
converted to steam and that the remaining solids are in a dry form. The solids
- rich gas flow 13 flows to
a dry solids separator 16. The dry solids separator is a commercially
available package and it can be used
in a variety of gas-solid separation designs. The removed solids 17 are taken
to a land-fill for disposal.
The steam flows to tower 25. The tower reacts as a direct contact heat
exchanger. Typically in MSF
processes, the feed water is heated in a vessel called the brine heater. This
is generally done by indirect
heat exchange by condensing steam on tubes that carry the feed water which
passes through the vessel.
The heated water then flows to the first stage. In the method described in
Fig. 11B, the feed water of
the MSF 45 is heated by direct contact heat exchange 25 (and not through an
indirect heat exchanger).
The feed water is injected into the up-flowing steam flow 12. The steam
condenses because of heat
exchange with the feed water 45. Non-direct heat exchanger / condensed can be
used as well to heat
brine flow 45 with steam flow 12 while condensing the steam flow 12 to liquid
water. In the MSF at
Block 30, the heated feed water 46 flows to the first stage 31 with a slightly
lower pressure, causing it to
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boil and flash into steam. The amount of flashing is a function of the
pressure and the feed water
temperature, which is higher than the saturate water temperature. The flashing
will reduce the
temperature to the saturate boiling temperature. The steam resulting from the
flashing water is
condensed on heat exchanger 32, where it is cooled by the feed water. The
condensate water 33 is
collected and used (after some treatment) 38 as BFW 39 in the standard,
commercially available, steam
generation facility 4. The number of stages can be up to 25. A commercial MSF
typically operates at a
temperature of 90-110C. High temperatures increase efficiency but may
accelerate scale formation and
corrosion in the MSF. Efficiency also depends on a low condensing temperature
at the last stage. The
feed water for the MSF 9 can be treated by adding inhibitors to reduce the
scaling and corrosion 38.
Those chemicals are available commercially and the pretreatment package is
typically supplied with the
MSF. The feed water is recovered from the produced water in separation unit 10
that separates the
produced bitumen 8, possibly with diluent that improves separation from the
water and the viscosity of
the heavy bitumen. The de-oiled water 9 is supplied to the MSF as feed water.
There are several
commercially available separation units. In my applications, the separation
can be simplified as
discharged "oily contaminate water" 18 is allowed in the process. Make-up
water 29, like water from
water wells or from any other water source, is continually added to the
system. Any type of vacuum
pump or ejector can be used to remove gas 36 and generate the low pressure
required in the MSF
design.
[61] FIGURE 12 is an illustration of the use of a partial combustion gasifier
with the present
invention for the production of syngas for use in steam generation, a SD-DCSG
and a DCSG combined
with a water distillation facility for ZLD. The system contains few a
commercially available blocks, each
of which includes a commercially available facility:
BLOCK 1 includes the gasifier that produces syngas.
BLOCK 2 includes a commercially available steam generation boiler that is
capable of combusting
syngas.
BLOCK 3 includes a commercially available thermal water distillation plant.
BLOCK 7 includes syngas treatment plant where part of the syngas can be used
for hydrogen
production etc.
BLOCK 5 includes a water-oil separation facility with the option of oily water
discharge for recycling
into the SD-DCSG.
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BLOCK 4 includes SD-DCSG which generates the injection steam.
BLOCK 6 includes DCSG.
Carbon fuel 5 is injected with oxygen rich 6 gas to a pressurized gasifier 7.
The gasifier shown is a typical
Texaco (GE) design that includes a quenching water bath at the bottom. Any
other pressurized partial
combustion gasifier design can also be used. The gasifier can include a heat
exchanger, located at the
top of the gasifier (near the combustion section), to recover part of the
partial combustion energy to
generate high pressure steam. At the bottom of the gasifier, there is a
quenching bath with liquid water
to collect solids. Make-up water 13 is then injected to maintain the liquid
bath water level. The
quenching water 15, which includes the solids generated by the gasifier, is
injected into a DCSG 15
where it is mixed with the produced hot syngas discharged from the gasifier
12. The DCSG also
consumes the liquid water discharge 52 from the SD-DCSG 50. In the DCSG, the
water is evaporated into
pressurized steam and solids (which were carried with the water and the syngas
into the DCSG). The
DCSG generates a stream of gas and solids 16. The solids 19 are removed from
the gas flow by a
separator 17 for disposal. The solids lean gas flow 18 (after most of the
solids have been removed from
the gas) is injected into a pressurized wet scrubber 20 that removes the solid
remains and can generate
saturated steam from the heat in gas flow 18 as well. Solids rich water 25 is
continually rejected from
the bottom of the scrubber and recycled back to the DCSG 15. Heat 27 is
recovered from the saturated
water and syngas mixture 21 while condensing steam 21 to liquid water 35 and
water lean syngas 36.
The condensed water 35 can be used as BFW after further treatment to remove
contaminations (not
shown). The heat 27 is used to operate a thermal distillation facility in
BLOCK 3. There are several
commercially available facilities for this, like MSF (Multi Stage Flashing) or
MED (Multi Effect
Distillation). The distillation facility uses de-oiled produced water 30,
possibly with make-up brackish
water 31 and heat 27, to generate a stream of de-mineralized BFW 29 for steam
generation and a
stream of brine water 28, with a high concentration of minerals. The generated
brine 28 is recycled back
to the SD-DCSG 50 in BLOCK 4. The syngas can be treated in commercially
available facilities BLOCK 7 to
remove H2S using amine or to recover hydrogen. The treated syngas 37, together
with oxidizer 38, is
used as a fuel source in the commercially available steam generation facility
BLOCK 2. The super heated
steam 40 is generated in steam boiler 39 from the BFW 29. The steam from the
boiler 40, possibly
together with the steam generated by the gasifier 10, is injected into the SD-
DCSG 50 in BLOCK 4 where
additional steam is generated from low quality water 53. The generated steam
51 is injected into an
underground formation for EOR. The produced bitumen and water recovered from
production well 44
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are separated in the water-oil separation facility BLOCK 5 to produce bitumen
33 and de-oiled water 30.
Oily water 34 can be rejected and consumed in the SD-DCSG 50. By allowing
continuous rejection of oily
water, the chemical consumption can be reduced and the efficiency of the oil
separation unit can be
improved.
[62] FIGURE 13 is a schematic of the present invention for the generation of
hot water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Block 1A includes a Prior Art
commercial open mine oilsands plant. The plant consists of mining oilsands ore
and mixing it with hot
process water, typically in a temperature range of 70C-90C, separating the
bitumen from the water,
sand and fines. The cold process water 8 includes recycled process water
together with fresh make-up
water that is supplied from local sources (like the Athabasca River in the
Wood Buffalo area). Another
bi-product from the open mine oilsands plant is Fine Tailing (FT) 5 which,
after a time, is transferred to a
stable Mature Fine Tailings (MFT). Energy 1 is being injected into reactor 3.
The energy is in the form of
steam gas. The hot, super heated ("dry") steam gas is mixed in enclosure 3
with a flow of FT 5 from
Block IA. Most of the liquid water in the FT is converted to steam. The
remaining solids 4 are removed
in a solid stable form to use as a back-fill material and support traffic. The
produced steam 21 is at a
lower temperature than steam 1 and contains additional water from the FT that
was converted to
steam. Steam 1 can be generated by heating the produced steam 21 as described
in Fig. 3, 3A or 3B (not
shown). The produce steam 21 is mixed with cold process water 8 from Block 1A
in a direct contact
heat exchanger 7. The produced steam directly heat and condense into the
liquid water 8 to generate
hot process water 9 that is supplied back to operate the Open Mine Oilsands
plant 1A. The amount of
Non Condensable Gases (NCG) 2 is minimal. Some NCG can be generated from the
organics
contaminates in the FT 5. The enclosure 3 system pressure can vary from 103kpa
to 50000kpa and the
temperature at the discharge point 21 can vary from 100C to 400C.
[63] FIGURE 13A is a schematic view for a process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Figure 13A is substantially similar
to figure 13 with the difference that non-direct heat exchange is used between
the drive steam 1 and
the FT or MFT 5. Block 1A includes a Prior Art commercial open mine oilsands
plant. The plant consists
of mining oilsands ore and mixing it with hot process water, typically in a
temperature range of 70C-
90C, separating the bitumen from the water, sand and fines. The cold process
water 8 includes recycled
process water together with fresh make-up water that is supplied from local
sources (like the Athabasca
River in the Wood Buffalo area). Another bi-product from the open mine
oilsands plant is Fine Tailing
(FT) 5 which, after a time, is transferred to a stable Mature Fine Tailings
(MFT). Energy 1 is being
CA 02748477 2011-08-02
injected into reactor 3. The energy is in the form of steam gas injected
around enclosure 3 where the
heat is transferred into the reactor and to the MFT through the enclosure
wall. The driving hot steam
gas is condensed and recovered as a liquid condensate 1A. The driving steam 1
heat energy is
transferred to the enclosure and used to evaporate the FT 5. Most of the
liquid water in the FT is
converted to steam. The remaining solids 4 are removed in a solid / slurry
stable form to use as a back-
fill material and support traffic. Steam 1 is generated by a standard boiler
heating the condensate 1A in
a closed cycle, allowing the use of high quality clean ASME BFW (not shown).
The produce steam 21 is
mixed with cold process water 8 from Block 1A in a direct contact heat
exchanger 7. The produced
steam directly heat and condense into the liquid water 8 to generate hot
process water 9 that is
supplied back to operate the Open Mine Oilsands plant 1A. The amount of Non
Condensable Gases
(NCG) 2 is minimal. Some NCG can be generated from the organics contaminates
in the FT S. The
enclosure 3 system pressure can vary from 103kpa to 50000kpa and the
temperature at the discharge
point 21 can vary from 1000 to 400C.
[64] FIGURE 13B is a schematic view for a process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Figure 13B is substantially similar
to figure 13A with rotating internals to enhance the heat transfer between the
evaporating MFT and
the heat source which is the steam 1 in the enclosure 3. The rotating
internals also mobilized the high
concentration slurry and solids to the solid discharge 4, where stable
material that can support traffic is
discharged from the system. The produce steam 6 is further cleaned to remove
solids in commercially
available solids separation unit 20 like cyclone, electrostatic filter or any
other commercial available
system. The generated steam 21 mixed with cold process water 8 supplied from
an open mine
extraction plant in a direct contact heat exchanger 7. The produced steam
directly heat and condense
into the liquid water 8 to generate hot process water 9 that is supplied back
to operate the extraction
Open Mine Oilsands plant.
[65] FIGURE 14 is one illustration of the present invention for the generation
of pre-heated
water that can be used for steam generation or mining extraction facility. The
invention has full disposal
water recycling, so as to achieve zero liquid discharge. Energy 1, in the form
of super heated steam is
introduced to the Direct Contact Steam Generator reactor 3. Contaminated water
5, like FT or MFT, is
injected into reactor 3. There, most of the water is converted to steam,
leaving solids with a low
moisture content. There are several possibilities for the design of reactor 3.
The design can be a
horizontal rotating reactor, an up-flow reactor, or any other type of reactor
that can be used to
generate a stream of solids and gas. A stream of hot gas 6, possibly with
carried-on solids generated in
CA 02748477 2011-08-02
reactor 3, flows into a commercially available solid-gas separator 20. Solids
4 can also be discharged
directly from the reactor 3, depending on the type of reactor used. The
separated solids 22 and 4 are
disposed of in a landfill. The solids lean steam flow 21, (rich with steam
from flow 5) condensed into
liquid water 10 in non-direct condenser 7. There are many commercially
available standard designed for
heat-exchanger / condenser that can be used at 7. The steam heat is used to
heat flow 8, like process
water flow, to generate hot water 9 that can be used in the extraction
process. Low volume of NCG 2
can be treated or combust as a heat source (not shown). The condensed liquid
water 10 can be used a
hot process water for the extraction process or any other usage. The steam in
flow 21 condenses by
non-direct contact with the recycled water 8. Solid remains that previously
passed through solid
separation unit 20 and were carried on with the gas flow 21, are washed with
the condensed water 10.
[66] FIGURE 15 is a schematic of the invention with an open mine oilsands
extraction
facility, where the steam source is a standard gasifier for generating steam
in non-direct hear exchange
and syngas that can be used for the production of hydrogen for upgrading the
produced crude in a
prior-art technologies or as a fuel source. The MFT recovery is done with the
steam produced by the
gasifier and not with the syngas. The partial combustion of fuel 56 and
oxidizer, like enriched air, takes.
place inside the gasifier 54. The gasification heat is used to produce
superheated steam 55 from BFW
(Boiler Feed Water) 59. The produce syngas 60 is recovered and further
treated. This treatment can
include the removal of the H2S (like in an amine plant). It can also include
generating hydrogen for
crude oil upgrading or as a fuel source to replace natural gas usage (not
shown). The steam 55 flows to
a horizontal parallel flow DCSG 1. Concentrated MFT 2 is also injected into
the DCSG. The MFT is
converted to gas- mainly steam, and solids 6. The solids 8 are removed in a
solid gas separator 7. The
solid lean stream flows through heat exchanger 11, where it heats the process
water or any other
process flow 12, indirectly through a heat exchanger. Condensing hot water 13
is removed from the
bottom of 11 and used as hot process extraction water. In case NCG 17 is
generated, it can be further
treated or combust as a fuel source. The fine tailings 14 are pumped from the
tailing pond and can then
be separated into two flows through a specific separation process. Separation
15 is one option to
increase the amount of MFT removal. The process can use natural MFT both at
flows 2 and 16. This
separation can be based on a centrifuge or on a thickener (like a High
Compression Thickener or
Chemical Polymer Flocculent based thickener). This unit separates the fine
tailings into solid rich 16 and
solid lean 2 flows. The solid lean flow is fed into the DCSG 1 or recycled and
used the process water (not
shown). In the DCSG 1 dry solids are generated and removed from the gas-solid
separator. The solid rich
flow 16 is mixed with the dry solids 8 in a screw conveyor to generate a
stable material 27.
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[67] FIGURE 16 is a schematic of the invention with an open mine oilsands
extraction
facility, where the hot process water for the ore preparation is generated by
recovering the heat and
condensing the steam generated from the fine tailings without the use of a
tailing pond. A typical mine
and extraction facility is briefly described in block diagram 1 (See "Past,
Present and Future Tailings,
Tailing Experience at Albian Sands Energy" presentation by Jonathan Matthews
from Shell Canada
Energy on December 8, 2008 at the International Oil Sands Tailings Conference
in Edmonton, Alberta).
Mined Oil sand feed is transferred in trucks to an ore preparation facility,
where it is crushed in a semi-
mobile crusher 3. It is also mixed with hot water 57 in a rotary breaker S.
Oversized particles are
rejected and removed to landfill. The ore mix goes through slurry
conditioning, where it is pumped
through a special pipeline 7. Chemicals and air are added to the ore slurry 8.
In the invention, the NCGs
(Non Condensed Gas) 58 that are released under pressure from tower 56 can be
added to the injected
air at 8 to generate aerated slurry flow. The conditioned aerated slurry flow
is fed into the bitumen
extraction facility, where it is injected into a Primary Separation Cell 9. To
improve the separation, the
slurry is recycled through floatation cells 10. Oversized particles are
removed through a screen 12 in the
bottom of the separation cell. From the flotation cells, the coarse and fine
tailings are separated in
separator 13. The fine tailings flow to thickener 18. To improve the
separation in the thickener,
flocculant is added 17. Recycled water 16 is recovered from the thickener and
fine tailings are removed
from the bottom of thickener 18. The froth is removed from the Primary
Separation Cell 9 to vessel 21.
In this vessel, steam 14 is injected to remove air and gas from the froth. The
recovered froth is
maintained in a Froth Storage Tank 23. The coarse tailings 15 and the fine
tailings 19 are removed and
sent to tailing processing area 60. The fine and coarse tailings can be
combined or removed and sent
separately (not shown) to the tailing process area 60. In unit 60, the sand
and other large solid particles
are removed and then put back into the mine, or stored in stock-piles. Liquid
flow is separated into 3
different flows, mostly differing in their solids concentration. A relatively
solids - free flow 62 is heated.
This flow is used as heated process water 57 in the ore preparation facility,
for generation of the
oilsands slurry 6. The fine tailings stream can be separated into two sub
streams. The most
concentrated fine tailings 51 are mixed with dry solids, generated by the
DCSG, to generate a solid and
stable substrate material that can be put back into the mine and used to
support traffic. The medium
concentrated fine tailing stream 61 flows to DCSG facility 50. Steam energy 47
is used in the DCSG to
convert the fine tailing 61 water into a dry or semi dry solid and gas stream.
The steam can be produced
in a standard high pressure steam boiler 40, in OTSG, or by a COGEN, using the
elevated temperature in
a gas turbine tail (not shown). The boiler consumes fuel gas 38 and air 39
while generating steam 14.
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Portion 47 of the generated steam 14 can be injected to the DCSG 50. The
temperature of the DCSG
produced steam can vary from 100C to 400C as it includes the water from the
MFT. Steam 47 can be
also generated by heating a portion of the produces steam 52 as described in
figures 3, 3A and 3B. The
solids are separated from the gas stream in any commercially available
facility 45 which can include:
cyclone separators, centrifugal separators, mesh separators, electrostatic
separators or other
combination technologies. The solids lean steam 52 flows into tower 56. The
gas flows up into the
tower, possibly through a set of trays, while any solid carried-on remnants
are scrubbed from the up
flowing gas through direct contact with liquid water. The water vapor that was
generated from heating
the fine tailing 61 in the DCSG and the steam that provided the energy to
evaporated the FT is
condensed and is added to the down-flowing extraction water process 57. The
presence of small
amounts of remaining solids in the hot process water can be acceptable. That
is because the hot water
is mixed with the crushed oilsands 3 in the breaker during ore preparation.
The temperature of the
discharged hot water 57 is between 70C and 95C, typically in the 80C-90C
range. The hot water is
supplied to the ore preparation facility. The separated dry solids from the
DCSG are mixed with the
concentrated slurry flow from the tailing water separation facility 60. They
are used to generate a
stable solid waste that can be returned to the oilsands mine for back-fill and
support traffic. Any
commercially available mixing method can be used in the process: a rotating
mixer, a Z type mixer, a
screw mixer, an extruder or any other commercially available mixer. The slurry
51 can be pumped to
the mixing location, while the dry solids can be transported pneumatically to
the mixing location. The
described arrangement, where the fine tailings are separated into two streams
61 and 51, is intended
to maximize the potential of the process to recover MFT. It is meant to
maximize the conversion of fine
tailings into solid waste for each unit weight of the supplied fuel source.
The system can work in the
manner described for tailing pond water recovery. The tailing pond water is
condensed into hot water
generation 57, without the combination of the dry solids 53 and tailing slurry
51. The generated dry
solids 53 are a "water starving" dry material. As such, they are effective in
the process of drying MFT
(Mature Fine Tailing), to generate trafficable solid material without relying
on weather conditions to dry
excess water.
[68] FIGURE 17 is a schematic of the invention with an open mine oilsand
extraction facility,
where the hot process water for the ore preparation is generated from
condensing the steam produced
from the fine tailings. A typical mine and extraction facility is briefly
described in block diagram 1. The
tailing water from the oilsands mine facility 1 is disposed of in a tailing
pond. The tailing ponds are built
in such a way that the sand tailings are used to build the containment areas
for the fine tailings. The
CA 02748477 2011-08-02
tailing sources come from Extraction Process. They include the cyclone
underflow tailings 13, mainly
coarse tailings and the fine tailings from the thickener 18, where flocculants
are added to enhance the
solid settling and recycling of warm water. Another source of fine tailings is
the Froth Treatment
Tailings, where the tailings are discarded using the solvent recovery process-
characterized by high
fines content, relatively high asphaltene content, and residual solvent. (See
"Past, Present and Future
Tailings, Tailing Experience at Albian Sands Energy" a presentation by
Jonathan Matthews from Shell
Canada Energy on December 8, 2008 at the International Oil Sands Tailings
Conference in Edmonton,
Alberta). A sand dyke 55 contains a tailing pond. The sand separates from the
tailings and generates a
sand beach 56. Fine tailings 57 are put above the sand beach at the middle-low
section of the tailing
pond. Some fine tailings are trapped in the sand beach 56. On top of the fine
tailing is the recycled
water layer 58. The tailing concentration increases with depth. Close to the
bottom of the tailing layer
are the MFT (Mature Fine Tailings). (See "The Chemistry of Oil Sands Tailings:
Production to Treatment"
presentation by R.J. Mikula, V.A. Munoz, O.E. Omotoso, and K.L. Kasperski of
CanmetENERGY, Devon,
Alberta, Natural Resources Canada on December 8, 2008 at the International Oil
Sands Tailings
Conference in Edmonton, Alberta). The recycled water 41 is pumped from a
location close to the
surface of the tailing pond (typically from a floating barge). The fine
tailings that are used for generating
steam and solid waste in my invention are the MFT. They are pumped from the
deep areas of the fine
tailings 43. Steam 48 is injected into a DCSG. MFT 43 is pumped from the lower
section of the tailing
pond and is then directed to the DCSG 50. The DCSG described in this
particular example is a horizontal,
counter flow rotating DCSG. However, any available DCSG that can generate gas
and solids from the
MET can be used as well. Due to the heat and pressure inside the DCSG, the MFT
turns into gas and
solids as the water is converted to steam. The solids are recovered in a dry
form or in a semi-dry, semi-
solid slurry form 51. The semi-dry slurry form is stable enough to be sent
back into the oilsands mine
without the need for further drying to support traffic. The produced steam 14,
that portion 48 can be
used to operate the DCSG is generated by a standard steam generation facility
36 from BFW 37, fuel gas
38 and air 39. The blow-down water 20 can be recycled into the process water
20. By continually
consuming the fine tailing water 43, the oil sand mine facility can use a much
smaller tailing pond as a
means of separating the recycled water from the fine tailings. This smaller
recyclable tailing pond is cost
effective, and it is the simplest way to do so as it does not involve any
moving parts (in contrast to the
centrifuge or to thickening facilities). This solution will allow for the
creation of a sustainable, fully
recyclable water solution for the open mine oilsands facilities. Steam 48 can
be generated by heating a
portion of the produces steam 47 as described in figures 3, 3A and 3B.
CA 02748477 2011-08-02
[69) FIGURE 18 is a schematic of the invention with open mine oilsands
extraction facility,
where the hot process water for the ore preparation is generated from
condensing the steam
generated from the fine tailings and the driving steam. The tailing water from
the oilsands mine facility
43 (not shown) is disposed of in a tailing pond. Steam 4 is fed into a
horizontal parallel flow DCSG 1.
Concentrated MFT 2 is injected into the DCSG 1 as well. The MFT is converted
to steam, and solids. The
solids are removed in a solid gas separator 7 where the solid lean stream is
washed in tower 10 by
saturated water. In the tower, the solids are washed out and then removed. The
solid rich discharge
flow 13 can be recycled back to the DCSG or to the tailing pond. Heat is
recovered from saturated
steam 16 in heat exchanger / condenser 17. Steam is condensed to water 20. The
condensed water 20
can be used as hot process water and can be added to the flow 24. The
recovered heat is used for
heating the process water 35. The fine tailings 32 are pumped from the tailing
pond and separated into
two flows by a centrifugal process 31. This unit separates the fine tailings
into two components: solid
rich 30 and solid lean 33 flows. The centrifuge unit is commercially available
and was tested successfully
in two field pilots (See "The Past, Present and Future of Tailings at
Syncrude" presentation by Alan Fair
from Syncrude on December 7-10, 2008 at the International Oil Sands Tailings
Conference in Edmonton,
Alberta). Other processes, like thickening the MFT with chemical polymer
flocculent, can be used as
well instead of the centrifuge. The solid lean flow can contain less than 1%
solids. The solid rich flow is
thick slurry ("cake") that contains more than 60% solids. The solid lean flow
is directly used or is
recycled back to a settling basin (not shown) and eventually used as process
water 35. The solid
concentration is not dry enough to be disposed of efficiently and to support
traffic. This can be solved
by mixing it with the "water starving" material (virtually dry solids
generated by the DCSG). Mixing of
the dry solids and the thick slurry can be achieved through many commercially
available methods. In
this particular figure, the mixture is done by a screw conveyer 29 where the
slurry 30 and the dry
material 8 are added to the bottom of a screw conveyor, mixed by the screw,
and then the stable solids
are loaded on a truck 28 for disposal. The produced solid material 27 can be
backfilled into the oilsands
mine excavation site and then used to support traffic. It is also possible to
feed the thickened MFT
directly to the DCSG 1, eliminating the additional mixing process. In this
particular figure, there are two
options for supplying the fine tailing water to the DCSG: one is to supply the
solid rich thick slurry 30
from the centrifuge or thickening unit 31. The other is to provide the
"conventional" MFT, typically with
30% solids, pumped from the settlement pond. Feeding the MFT "as is" to the
DCSG eliminates the TIC,
operation, and maintenance costs for a centrifuge or thickening facility.
CA 02748477 2011-08-02
[70] FIGURE 19 is an illustration of one embodiment of the present invention.
Fuel 2 is
mixed with oxidizing gas 1 and injected into the steam boiler 4. The boiler is
a commercially available
atmospheric pressure boiler. If a solid fuel boiler is used, the boiler might
include a solid waste
discharge. The boiler produces high-pressure steam 5 from distilled BFW 19.
The steam is injected into
the underground formation through injection well 6 for EOR. The boiler
combustion gas are possibly
cleaned and discharged from stack 32. If natural gas is used as the fuel 2,
there is currently no
mandatory requirement in Alberta to further treat the discharged flue gas or
remove CO2. Steam 9 is
injected into a pressurized, direct - contact steam generator (DCSG) 15 at an
elevated pressure. The
DCSG design can include a horizontal rotating reactor, a fluidized bed reactor
and an up-flow reactor or
any other reactor that can be used to generate a stream of gas and solids.
Solids - rich water 14 is
injected into the direct contact steam generator 15 where the water evaporates
to steam and the solids
are carried on with gas flow 13. The amount of water 14 is controlled to
verify that all the water is
converted to steam and that the remaining solids are in a dry form. The solid -
rich gas 13 flows to a dry
solids separator 16. The dry solids separator is a commercially available
package and it can be used in a
variety of gas-solid separation designs. The solids 17 are taken to a land-
fill. The solids lean flow 12
flows to the heat exchanger 30. The steam continually condenses because of
heat exchange. Heat 25 is
recovered from gas flow 12. The condensed water 36 can be used for steam
generation. The
condensation heat 25 can be used to supply the heat to operate the
distillation unit 11. The distillation
unit 11 produces distillation water 19. The brine water 26 is recycled back to
the direct contact steam
generator 15 where the liquid water is converted to steam and the dissolved
solids remain in a dry
form. The distillation unit 11 receives de-oiled produced water 39 that is
separated in a commercially
available separation facility 10 like that which is currently in use by the
industry. Additional make-up
water 34 is added. This water can be brackish water, from deep underground
formation, or from any
other water source that is locally available to the oil producers. The quality
of the make-up water 34 is
suitable for the distillation facility 11, where there are typically very low
levels of organics due to their
tendency to damage the evaporator's performance or carry on and damage the
boiler. Water that
contains organics is a by-product of the separation unit 10 and it will be
used in the DCSG 15. By
integrating the separation unit 10 and the DCSG 15, the organic contaminated
by-product water can be
used directly, without any additional treatment by the DCSG 15. This
simplifies the separation facility 10
that can reject contaminated water without environmental impact. It is sent to
the DCSG 15, where
most of the organics are converted to hydrocarbon gas phase or carbonic with
the hot steam gas flow.
The distilled water 19 produced by the distillation facility 11, possibly with
the condensed steam from
CA 02748477 2011-08-02
flow 12, are sent to the commercially available, non-direct, steam generator
4. The produced steam 5 is
injected into an underground formation for EOR. The brine 26 is recycled back
14 to the DCSG and
solids dryer 15 as described before. The production well 7 produces a mixture
of tar, water and other
contaminants. The oil and the water are separated in commercially available
plants 10 into water 9 and
oil product 8.
[71) FIGURE 20 is an illustration of one embodiment of the present invention.
It is similar to
FIG. 19 with the following modifications described below: The solids lean flow
12 is mixed with
saturated water 21 in vessel 20. The heat carried in the steam gas 12 can
generate additional steam if
its temperature is higher than the saturated water 21 temperature. The solids
carried with the steam
gas are washed by saturated liquid water 23. The solids rich water 24 is
discharged from the bottom of
the vessel 20 and recycled back to the DCSG 15 where the liquid water is
converted to steam and the
solids are removed in a dry form for disposal. Saturated "wet" solids free
steam 22 flows to heat
exchanger / condenser 30. The condensed water 36 is used for steam generation.
The condensation
heat 25 is used to operate a water treatment plant 11 as described in FIG. 19
above. To minimize the
amount of steam 9 used to drive the DCSG 15, it is possible to recycled
portion of the produced
saturated steam 22 as described in Fig. 3, 3A and 3B. This option is shown in
dotted line. Portion of the
produced steam 22 is recycled to drive the process. This steam is compressed
42 to allow the recycle
flow and overcome the heater and the SD- DCSG pressure drop. The steam is
heated in a non-direct
heat exchanger 41. Any type of heat exchanger / heater can be used at 41. One
example is the use of a
typical re-heater 43 that is a typical part from a standard boiler design.
[72] FIGURE 21 is an illustration of a boiler, steam drive DCSG, solid removal
and Mechanical
Vapor Compression distillation facility for generating distilled water for
steam generation in the boiler
for EOR. Block 4 includes a steam generation unit. Fuel 2, possibly with water
in a slurry form, is mixed
with air 1 and injected into a steam boiler 4. The boiler may have waste
discharged from the bottom of
the combustion chamber. The boiler produces high-pressure steam 3 from treated
distillate feed water
5. The steam is injected into the underground formation through injection well
21 for EOR. Part of the
steam 7 is directed to drive a DCSG 9. Block 22 includes a steam drive DCSG 9.
Solids rich water, like
concentrate brine 8 from distillation facility, is injected to the DCSG 9
where the water is mixed with
super heated steam 7. The liquid water phase is converted to steam due to the
high temperature of the
driving steam 7. The DCSG can be a commercially available direct-contact
rotary dryer or any other type
of direct contact dryer capable of generating solid waste and steam from solid
- rich brine water 8. The
DCSG generates a stream of steam gas 10 with solid particles from the solid
rich water 8. The DCSG in
CA 02748477 2011-08-02
Block 22 can generate its own driving steam 7 by recycling and heating portion
of the saturated
produced steam 12 as described in Fig. 3, 3A and 3B (not shown). The amount of
water 8 is controlled
to verify that all the water is converted to steam and that the remaining
solids are in a dry form. The
solid - rich steam gas flow 10 is directed to Block 21 which separates the
solids. The solid separation is
in a dry solids separator 12. The dry solids separator is a commercially
available package and it can be
used in a variety of gas-solid separation designs. The solids lean flow 11 is
mixed with saturated water
22 in a direct contact wash vessel 15. The solids remains carried with the
steam are washed by
saturated liquid water 22. The solids rich water 14 is discharged from the
bottom of the vessel 22 and
recycled back to dryer 9 where the liquid water is converted to steam and the
solids are removed in a
dry form for disposal. If the dry solid removal efficiency at 12 is high, it
is possible to eliminate the use
of the saturate water liquid scrubber 15. The produced saturated steam 23 is
supplied to Block 20,
which is commercially available distillation unit produces distillation water
S. The brine water 8 is
recycled back to the direct contact steam generator / solids dryer 15 where
the liquid water is
converted to steam and the dissolved solids remain in dry form. Distillation
unit 19 is a Mechanical
Vapor Compression (MVC) distillation facility. It receives de-oiled produced
water 16 that has been
separated in a commercially available separation facility currently in use by
the industry with additional
make-up water (not shown). This water can be brackish, from deep underground
formations or from
any other water source that is locally available to the oil producers. The
quality of the make-up water is
suitable for the distillation facility 20, where there are typically very low
levels of organics due to their
tendency to damage the evaporator's performance or damage the boiler further
in the process. The
distilled water produced by distillation facility 19 is treated by the
distillate treatment unit 17, typically
supplied as part of the MVC distillation package. The treated distilled water
5 can be used in the boiler
to produce 100% quality steam for EOR. The brine 8 and possibly the scrubbing
water 14 are recycled
back to the DCSG/dryer 9 as previously described. The heat from flow 23 is
used to operate the
distillation unit in Block 20. The condensing steam from flow 23 recovered in
the form of liquid distilled
water 5. The high - pressure steam from the boiler in Block 4 is injected into
the injection well 21 for
FOR or for other uses (not shown). With the use of a low pressure system, the
thermal efficiency of the
system is lower than using a high pressurized system with pressurized DCSG
instead of a low pressure
dryer.
[73] The following are example for heat and material balance simulation:
CA 02748477 2011-08-02
[74] Example 1: The graph in figure 22 simulates the process as described in
Figure 2A.
The system pressure was constant at 25bar. The liquid water 7 was at
temperature of 25C with a
constant flow of 1000 kg/hour. The product 8 was saturated steam at 25bar. The
graph shows the
amount of drive steam 9 required to transfer the liquid water 7 into gas phase
as a function of the
temperature of the driving steam 9. When 300C driving steam is used, there is
a need in 12.9ton/hour of
steam 9 to gasify one ton/hour of liquid water 7. When 500C driving steam is
used, there is a need in
only 4.1ton/hour of steam 9 to gasify one ton/hour of liquid water 7. The
following are the result of the
simulation:
Drive Drive
Steam 9 Steam 9 Flow
Temperature(C ) (kg/hr)
600.00 3059.20
550.00 3502.50
500.00 4091.50
450.00 4914.46
400.00 6159.21
350.00 8290.00
300.00 12990.00
250.00 34950.00
CA 02748477 2011-08-02
[75] Example 2: The graph in Figure 23 simulates the process as described in
Figure 2A. The
driving steam 9 temperature was constant at 450C . The liquid water 7 was at
temperature of 25C and
constant flow of 1000kg/hour. The produced steam product 8 was saturated. The
graph shows the
amount of drive steam 9 required to transfer the liquid water 7 into gas phase
as a function of the
pressure of the driving steam 9. When the system pressure was 2 bar, a 3.87
ton/hour of driving steam
was needed to convert the water to saturated steam at temperature of 121C .
For 50 bar system
pressure, 5.14 ton/hour of driving steam was used to generate saturated steam
at 256C . The
simulation results summarized in the following table:
System Temperature of Driving steam
Pressure Saturated pressure
(bar) produced Steam (kg/hr)
100.00 311.82 5127.94
75.00 291.35 5161.78
50.00 264.74 5135.66
25.00 224.70 4914.46
20.00 213.11 4821.42
15.00 198.98 4696.41
10.00 180.53 4515.83
5.00 152.40 4218.44
3.00 134.03 4018.992
2.00 120.68 3870.57
1.00 100.00 3649.728
CA 02748477 2011-08-02
[76] Example 3: The graph in Figure 24 simulates the process as described in
Figure 2A
where the water feed includes solids and naphtha. As the pressure increases,
the saturated
temperature of the steam also increases from around 100C at ibar to around
312C 100bar. Thus the
amount of superheated steam input at 450C also increases from around 2300
kg/hr to 4055 kg/hr. The
graph in Figure 24 represents the superheated driving steam input 9 and the
total flow rate (including
hydrocarbons) of the produced gas 8.
Flow Number 7 12
f,C 25.00 450.00 120.61 120.61
P,atm 2.00 2.00 2.00 2.00
Vapor Fraction 0.00 1.00 0.00 1.00
Enthalpy, MJ -14885.08 29133.36 -6692.49 37325.62
Total Flow, kg/hr 1000.00 2311.54 414.73 2896.81
Water 600.00 2311.54 114.20 2797.34
Solids 300.00 0.00 300.00 4.14E-17
Naptha 100.00 .00 .53 9.47
CA 02748477 2011-08-02
[77] Example 4: The following table simulates the process as described in
Figure 3 for
insitue oilsands thermal extraction facility like SAGD for two different
pressures. The water feed is hot
produced water at 200C that includes solids and bitumen. The heat source Q'
for the simulation was
12KW.
For system pressure of 400psi the total inflow of Water + solids + Bitumen of
flow 34 were 23.4 kg. 77%
of the steam 31 recycles as the driving steam 32 while 23% is discharged out
of system at 283C Steam +
hydrocarbons.
For system pressure of 600psi the total Inflow of Water + solids + Bitumen of
flow 34 were 22.5 kg. 80%
of the steam 31 recycles as the driving steam 32 while 20% is discharged out
of system at 283C Steam +
hydrocarbons.
Flow Number 34 35 31 32 36 33
T, C 200 243.42 243.42 243.43 486.73 243.43
Press., psig 400 400 400 400 400.00 400.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00
Enthalpy, kW -96.591 -5.06 -346.24 -266.80 -254.78 -79.69
Total Flow, kg/hr 23.4 1.17 96.89 74.66 74.66 22.30
Water, kg/hr 21.76 0.00 94.84 73.08 73.08 21.83
Solids 1.17 1.17 0.00 0.00 0.00 0.00
Hydrocarbons 0.470 0.000 2.048 1.578 1.578 0.471
Flow Number 34 35 31 32 36 33
T, C 200 243.42 243.42 243.43 486.73 243.43
Press., psig 400 400 400 400 400.00 400.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00
Enthalpy, kW -96.591 -5.06 -346.24 -266.80 -254.78 -79.69
Total Flow, kg/hr 23.4 1.17 96.89 74.66 74.66 22.30
Water, kg/hr 21.76 0.00 94.84 73.08 73.08 21.83
Solids 1.17 1.17 0.00 0.00 0.00 0.00
hydrocarbons 0.470 0.000 2.048 1.578 1.578 0.471
CA 02748477 2011-08-02
[78] Example 5: The following process simulation described in Figure 30
simulates a 600psi
system pressures. The graph in Figure 30 simulates the impact of the produced
water feed temperature
on the overall process performance. Hot produced water that includes solids
and bitumen
contaminates is typical to insitue oilsands thermal extraction facility like
SAGD. The graph shows that
for a constant heat flow, as the produced feed water temperature increases, so
the amount of produce
steam increases accordingly. The heat source Q' in the simulation was 12KW.
The driving steam 36
temperature was 900F. 80% of the steam 31 recycled to the heater as the
driving steam 36 while 20% is
discharged out of system at 283C Steam + hydrocarbons. The simulation shows
that for feed water at a
temperature of 20C, amount of 15.1kg of produced steam is generated. For
temperature of 100C,
17.4kg of produced steam is produced and for temperature of 220C, 22.4kg of
produced steam is
produced.
[79] Example 6: The following table simulates the process as described in
Figure 4 for insitue
oilsands thermal extraction facility like SAGD. The water feed is hot produced
water at 200C that
includes solids and bitumen. The heat source Q' for the simulation was 12KW
and the system pressure
600psi. The total Inflow of Water + solids + Bitumen of flow 47 was 22.5 kg.
79% of the steam 31
recycles as the driving steam 36 while 21% is discharged out of system at 294C
Steam + hydrocarbons.
In the simulation 4.9kw removed at the flash/condensation unit 42 and used to
pre-heat water feed 47.
The product was split from flow 31 (not shown on figure 4) replacing flow 46.
Flows 44 and 45 were
equal in this simulation.
Product (split
Flow Number 47 35 31 33 36 45 43 from 33)
T, C 200 294.91 294.91 294.91 471.55 253.81 253.81 294.91
Press., psig 600 600.00 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00 0.13 1.00
Enthalpy, kW -92.863 -4.76 -361.07 -285.24 -261.99 -274.01 -15.89 -75.82
Total Flow,
kg/hr 22.5 1.13 101.76 80.39 74.82 74.82 5.56 21.37
Water, kg/hr 20.925 0.00 99.64 78.72 74.82 74.82 3.90 20.92
S102 1.125 1.13 0.00 0.00 0.00 0.00 0.00 0.00
hydrocarbons 0.450 0.000 2.118 1.673 0.000 0.000 1.668 0.445
CA 02748477 2011-08-02
[80] Example 7: The following table is a simulation results for the process
describes in
Figure 25. The water feed 1 is produced water from a SAGD separator and
includes solids and
hydrocarbons at a high temperature of 200C. The produced water 1 is mixed with
superheated steam 7
at approximately 900F. Recycled water 12 from scrubber 23 is recycled back to
the water feed 1. Solid
contaminates 3 are removed from separator 21. The produced steam 4 is divided
into two flows -
portion 6 of the produced steam (22%) at temperature of 285C and 600psi
pressure is recovered from
the system as the product for steam injection or any other use. The rest 78%
of the produced steam 5 is
cleaned in a wet scrubber with saturated water, potentially with additional
chemicals that can
efficiently removed silica and possibly other contaminates introduced with the
produced water (like
magnesium based additives, soda caustic and others). Water 9 is feed into the
scrubber 23 and the
scrubbed water 12 is continually recycled back to the stage of the steam
generation. The scrubbed
steam 8 is compressed by mechanical means or by steam ejector 24 to a heater
25. In the simulation a
12kw heater was used 25 to simulate bench scale laboratory facility. In a
commercial plant any heater
can be used. The system simulation pressure was 600psig. The superheated steam
7 is used as the
driving steam to drive the process. Another option to minimize the risk of
build-ups in the injection
piping is to recover the produce steam 6 from flow 8 (indicates on Figure 25
as flow 6A)
Flow Number 1 2 3 4 5 6 7 8 9 10 12
T, C 200 284.78 284.78 284.78 284.77 284.77 478.12 253.81 20.00 254.1311
253.81
Press., psig 600 600.00 600.00 600.00 600.00 600.00 600.00 600.00 600.00
601.4696 600.00
Vapor Fraction 0 1.00 0.00 1.00 1.00 1.00 1.00 1.00 0.00 1 0.00
Enthalpy, kW -74.2904 330.80 -3.82 326.94 255.03 -71.93 255.05 267.08 -13.25 -
267.046 -1.21
Total Flow,
kg/hr 18 92.53 0.90 91.63 71.47 20.16 72.92 72.93 3.00 72.9221 1.55
Water, kg/hr 16.74 90.01 0.00 90.01 70.21 19.80 72.92 72.93 3.00 72.92209 0.28
Solids 0.9 0.90 0.90 0.00 0.00 0.00 0.00 0.00 0.00 0 0.00
Hydrocarbons 0.360 1.618 0.000 1.618 1.262 0.356 0.000 0.000 0.000 6.99E-06
1.262
[81] Example 8: The following table is a simulation results for the process
describes in
Figure 26. The water feed 1 is produced water from a SAGD separator and
includes solids and
hydrocarbons at a high temperature of 200C. (The produced water 1 is at a much
lower flow of approx.
8kg/hour compared to the flow of 18kg/hour in example 25 because additional
treated boiler feed
water 10 is added later). The feed 1 is mixed with superheated steam 7 at
approximately 900F. Recycled
water 12 from scrubber 23 is recycled back to the water feed 1. Solid
contaminates 3 are removed from
CA 02748477 2011-08-02
separator 21. The produced steam 4 is divided into two flows - portion 6 of
the produced steam (75%)
at temperature of 271C and 600psi pressure is recovered from the system as the
product for steam
injection or any other use. The rest 25% of the produced steam 5 is cleaned in
a wet scrubber with
saturated water, potentially with additional chemicals to remove contaminates.
Water 9 at flow of
0.3kg/hour and temperature of 20C is feed into the scrubber 23 and the
scrubbed water 12 is
continually recycled back to the stage of the steam generation. The scrubbed
steam 8 is condensed by
direct contact with clean BFW 10 at flow of 10kg/hour and temperature of 20C.
The generated water 11
at temperature of 250C is pumped to low overpressure to generate circulation
and compensate for the
losses and generated into superheated steam by 12kw heater 25 to simulate
bench scale laboratory
facility. In a commercial plant any commercial boiler can be used to produce
the superheated dry
steam. The system simulation pressure was 600psig. The superheated steam 7 at
flow of 16kg/hour is
used as the driving steam to drive the process. Another option to minimize the
risk of build-ups in the
injection piping is to recover the produce steam 6 from flow 8 (indicates on
Figure 25 as flow 6A)
Flow No. 1 2 3 4 5 6
T, C 200.00 271.89 271.89 271.89 271.88 271.88
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0.00 0.99 0.00 1.00 1.00 1.00
Enthalpy, kW -32.47 -87.32 -1.66 -85.64 -21.42 -64.27
Total Flow, kg/hr 7.870 24.105 0.390 23.715 5.932 17.797
Water, kg/hr 7.320 23.500 0.000 23.500 5.879 17.636
Solids 0.390 0.390 0.390 0.000 0.000 0.000
Hydrocarbons 0.160 0.215 0.000 0.215 0.054 0.161
Flow No. 7 8 9 10 11 12
T, C 660.37 253.81 20.00 20.00 250.31 253.81
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 1.00 1.00 0.00 0.00 0.00 0.00
Enthalpy, kW -53.87 -21.71 -1.32 44.1606 -65.87 -1.04
Total Flow, kg/hr 15.927 5.927 0.300 10.000 15.927 0.305
Water, kg/hr 15.927 5.927 0.300 10.000 15.927 0.251
Solids 0.000 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.000 0.054
CA 02748477 2011-08-02
[82] Example 9: The following table is a simulation results for the process
describes in Figure
27. The simulation is similar to example 8 with change to the production of
the boiler feed water where
instead of using clean Boiler Feed water to condensate the generated steam for
generating the
superheated steam generator feed water, heat is recovered to condensed the
steam to BFW and
introduced back to the system to heat the feed water. By this arrangement the
need in fresh BFW is
eliminated and replaced by condensation. Water feed 1 is heated with Q-in that
is a heat recovered
from the condensation and mixed with superheated steam 7. Recycled water 12
from scrubber 23 is
recycled back to the water feed 1. Solid contaminates 3 are removed from
separator 21. The produced
steam 4 is divided into two flows - portion 6 of the produced steam (53%) at
temperature of 282C and
600psi pressure is recovered from the system as the product for steam
injection or any other use. The
rest 47% of the produced steam 5 is cleaned in a wet scrubber with saturated
water, potentially with
additional chemicals to remove contaminates. Water 9 at flow of 4.1kg/hour and
temperature of 20C is
feed into the scrubber 23 and the scrubbed water 12 is continually recycled
back to the stage of the
steam generation. The scrubbed clean steam 8 is condensed by recovering the
condensation heat Q-out
that is return back to the system for pre-heating the feed water as Q-in or
for pre-heating other streams
like 9. The generated water 11 at temperature of 254C is pumped to low
overpressure to generate
circulation and compensate for the losses and generated into superheated steam
by 12kw heater 25 to
simulate bench scale laboratory facility. In a commercial plant any commercial
boiler can be used to
produce the superheated dry steam. The system simulation pressure was 600psig.
The superheated
steam 7 at flow of 18.7kg/hour is used as the driving steam to drive the
process. Another option to
minimize the risk of build-ups in the injection piping is to recover the
produce steam 6 from flow 8
(indicates on Figure 25 as flow 6A)
Flow No. 1 2 3 4 5 6
T, C 200.00 282.56 282.56 282.56 282.52 282.52
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0.00 0.99 0.00 1.00 1.00 1.00
Enthalpy, kW -86.378 -145.07 -4.46 -140.57 -66.07 -74.51
Total Flow,
kg/hr 20.930 40.518 1.050 39.468 18.552 20.920
Water, kg/hr 19.460 38.678 0.000 38.678 18.180 20.501
Solids 1.050 1.050 1.050 0.000 0.000 0.000
Hydrocarbons 0.420 0.791 0.000 0.791 0.372 0.419
Flow No. 7 8 9 11 12
T, C 493.17 253.81 20.00 253.81 253.81
CA 02748477 2011-08-02
Press., psig 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 1.00 1.00 0.00 0.00 0.00
Enthalpy, kW -65.12 -68.38 -4.42 -77.12 -2.11
Total Flow,
kg/hr 18.671 18.671 1.000 18.671 0.881
Water, kg/hr 18.671 18.671 1.000 18.671 0.509
Solids 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.372
[83] Example 10: The following table is a simulation results for the process
describes in
Figure 28. The water feed 1 is tailings water from an open mine oilsands
extraction facility. The feed
water includes 30% solids and 3% solvents at low temperature of 20C. The
system is low pressure, close
to atmospheric pressure. The produced water 1 is mixed with superheated steam
7 at 535C. Solid
contaminates 3 are removed from separator 21. The produced steam 4 is divided
into two flows -
portion 5 of the produced steam (70%) at temperature 99.7C is recycled, using
mechanical
compression, ejector (not shown) or any other means to generating the recycle
flow. The recycled
steam 5 is heated with 12kw heat source to generate superheat steam 7 at
temperature of 534C. The
rest 30% of the produced steam 8 is condensed by direct contact mixture with
process water 9 at
temperature of 20C to generate 80C process water that can used in the
extraction process. The
produced steam 4 can be furthered clean with any dry or wet commercial
available cleaning systems,
like a wet scrubber (not shown) with saturated water, possibly with additional
chemicals to remove
contaminates. This cleaning can prevent build-ups at the recycling low
pressure compressing unit and
the heating unit 25. A total of 206 kg/hour hot water is generated at this
simulation from 12kw heat
sorce.
Flow Number 1 2 3 4 5 6
T, C 20.00 99.73 99.73 99.73 99.73 108.00
Press., atm 1.00 1.00 1.00 1.00 1.00 1.10
Vapor Fraction 0.00 0.88 0.00 1.00 1.00 1.00
Enthalpy, kW -132.07 -293.79 -41.37 -248.71 -174.10 -173.88
Total Flow,
kg/hr 30.00 78.84 9.00 69.84 48.89 48.89
Water, kg/hr 20.10 66.85 0.00 66.85 46.79 46.79
Solids 9.00 9.00 9.00 0.00 0.00 0.00
N-Butane 0.45 1.50 0.00 1.50 1.05 1.05
CA 02748477 2011-08-02
N-Pentane 0.32 1.05 0.00 1.05 0.73 0.73
N-Hexane 0.14 0.45 0.00 0.45 0.31 0.31
Flow Number 7 8 9 10 11
T, C 534.94 99.73 20.00 80.11 80.11
Press., atm 1.00 1.00 1.00 1.00 1.00
Vapor Fraction 1.00 1.00 0.00 1.00 0.00
Enthalpy, kW -161.88 -74.61 -821.39 -0.61 -895.39
Total Flow,
kg/hr 48.89 20.95 186.00 0.51 206.44
Water, kg/hr 46.79 20.05 186.00 0.10 205.95
Solids 0.00 0.00 0.00 0.00 0.00
N-Butane 1.05 0.45 0.00 0.26 0.18
N-Pentane 0.73 0.31 0.00 0.12 0.20
N-Hexane 0.31 0.13 0.00 0.03 0.11
[84] Example 11: The following table is a simulation results for the process
describes in
Figure 29. The water feed 1 is tailings water from an open mine oilsands
extraction facility. The feed
water includes 30% solids and 3% solvents at low temperature of 20C. The
system is low pressure, close
to atmospheric pressure. The produced water 1 is mixed with superheated steam
7 at 492C. Solid
contaminates 3 are removed from separator 21. The produced steam is condensed
by direct contact
mixture with process water 9 at temperature of 20C to generate 80C process
water that can use in the
extraction process. Portion of the produced water is heated in boiler 25 to
generate superheated
steam. The flow to produced the steam 5 can be further treated to remove
contaminates to increase its
quality to BFW quality water. Another option is to split the produce steam 4,
scrub portion, condensed
the clean scrubbed steam to water, possibly with water from an exterior source
and used the clean
condensate to generate the super heated steam 7. This option was described in
other figures but is not
reflected in the current simulation.
Flow No. 1 2 3 4 5 6
T, C 20 110.46 110.46 110.46 80.07 80.07
Press., atm 1 1.00 1.00 1.00 1.00 1.10
Vapor Fraction 0 1.00 0.00 1.00 0.00 0.00
Enthalpy, kW 20.3134 -68.23 -2.51 -65.72 -59.92 -59.92
Total Flow,
kg/hr 6 19.80 1.80 18.00 13.80 13.80
Water, kg/hr 4.02 17.81 0.00 17.81 13.79 13.79
CA 02748477 2011-08-02
Solids 1.8 1.80 1.80 0.00 0.00 0.00
Hydrocarbons 0.180 0.194 0.000 0.194 0.015 0.015
Flow No. 7 8 9 10 11
T, C 492.40 80.07 20.00 80.07 80.07
Press., atm 1.00 1.00 1.00 1.00 1.00
Vapor Fraction 1.00 0.00 0.00 1.00 0.00
Enthalpy, kW -47.91 -803.20 -737.48 0.00 -743.28
Total Flow,
kg/hr 13.80 185.00 167.00 0.00 171.20
Water, kg/hr 13.79 184.81 167.00 0.00 171.02
Solids 0.00 0.00 0.00 0.00 0.00
Hydrocarbons 0.015 0.194 0.000 0.000 0.180
[85]
[86]
CA 02748477 2011-08-02
STEAM DRIVE DIRECT CONTACT STEAM GENERATION
BACKGROUND OF THE INVENTION
1. Field of the Invention
[01] This application relates to a system and method for producing steam from
contaminated water feed for Enhanced Oil Recovery (EOR). This invention
relates to processes for
directly using steam energy, preferably superheated dry steam, for generating
additional steam from
contaminated water by direct contact, and using this produced steam for
various uses in the oil industry
and possibly in other industries as well. The produced steam can be injected
underground for Enhanced
Oil Recovery. It can also be used to generate hot process water at the mining
oilsands industry. The high
pressure drive steam is generated using commercially available, non-direct
steam boiler, co-gen, OTSG
or any steam generation system or steam heater. Contaminates, like suspended
or dissolved solids
within the low quality water feed, can be removed in a stable solid (former
Liquid Discharge) system.
The system can be integrated with combustion gas fired DCSG (Direct Contact
Steam Generator) for
consuming liquid waste streams or with distillation and systems.
[02] The injection of steam into heavy oil formations was proven to be an
effective method
for FOR and it is the only method currently used commercially for recovery of
bitumen from deep
underground oilsand formations in Canada. It is known that FOR can be achieved
where combustion
gases, mainly C02, are injected into the formation, possibly with the use of
DCSG as described in my
previous applications. The problem is that oil producers are reluctant to
implement significant changes
to their facilities, especially if they include changing the composition of
the injected gas to the
underground formation and the risk of corrosion in the carbon steel pipes due
to the presence of the
C02. Another option to fulfill this requirement and generate steam from low
grade produced water with
ZLD is to operate the DCSG with steam instead of a combustion gas mixture that
includes, in addition to
steam, other gases like nitrogen, carbon dioxide, carbon monoxide and other
gases. The driving steam is
generated by a commercially available non-direct steam generation facility.
The driving steam is directly
used to transfer liquid water into steam and solid waste. In FOR facilities
most of the water required for
steam generation is recovered from the produced bitumen-water emulsion. The
produced water has to
be extensively treated to remove the oil remains that can damage the boilers.
This process is expensive
and consumes large amount of chemicals. The SD-DCSG (Steam Drive - Direct
Contact Steam Generator)
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can consume the contaminated water feed for generating steam. The SD-DCSG can
be stand alone
system or can be integrated with combustion gas DCSG as described in this
application. The proposed
SD-DCSG is also suitable for oilsands mining projects where the FT (Fine
Tailings) or MFT (Mature Fine
Tailings) are heated and converted to solids and steam using the driving steam
energy. The produced
steam from the SD-DCSG can be used to heat the process water in a direct or
non-direct heat exchange.
The hot process water is mix with the mined oilsands ore during the extraction
process.
[03] The steam for the SD-DCSG can be provided directly from a power station.
The most
suitable steam will be the medium pressure, super-heated steam as typically
fed to the second or third
stage of steam turbine. A cost efficient, hence effective system will be to
employ a high pressure steam
turbine to generate electricity. The discharge steam from the turbine, at a
lower pressure, can be
recycled back to the boiler re-heater to generate a super heated steam which
is effective as a driving
steam. Due to the fact that the first stage turbine, which is the smallest
size turbine, produces most of
the power (due to a higher pressure), the cost per Megawatt of the steam
turbine will be relatively low.
The efficiency of the system will not be affected as the superheated steam
will be used to drive the SD-
DCSG directly and generating injection steam for enhanced oil recovery unit
with Zero Liquid Discharge
(ZLD). A ZLD facility is more environmentally friendly compared to a system
that generates reject water
and sludge.
[04] The definition of "Steam Drive - Direct Contact Steam Generation" (SD-
DCSG) is that
steam is used to generate additional steam from direct contact heat transfer
between the liquid water
and the combustion gas. This is accomplished through the direct mixing of the
two flows (the water and
the steam gases). In the SD-DCSG, the driving steam pressure is similar to the
produced steam pressure
and the produced steam is a mixture of the two.
[05] The driving steam is generated in a Non-Direct Steam Generator (like a
steam boiler
with a steam drum and a mud drum) or "Once Through Steam Generator" (OTSG)
COGEN that uses the
heat from a gas turbine to generate steam or any other available design. The
heat transfer and
combustion gases are not mixed and the heat transfer is done through a wall
(typically a metal wall),
where the pressure of the generated steam is higher than the pressure of the
combustion. This allows
for the use of atmospheric combustion pressure. The product is pure steam (or
a steam and water
mixture, as in the case of the OTSG) without combustion gases.
[06] There are patents and disclosures issued in the field of the present
invention. US patent
No. 6,536,523 issued to Kresnyak et al. on March 25, 2003 describes the use of
the blow-down heat as
the heat source for water distillation of de-oiled produced water in a single
stage MVC water distillation
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unit. The concentrated blow-down from the distillation unit can be treated in
a crystallizer to generate
solid waste.
[07] US Patent application 12/702,004 filed by Minnich et al. and published on
August 12,
2010 describes a heat exchanger that operates on steam for generating steam in
an indirect way from
low quality produced water that contains impurities. In this disclosure, steam
is used indirectly to heat
the produced water that include contaminates. By using steam as the heat
transfer medium the direct
exposure of the low quality water heat exchanger to fire and radiation is
prevented, thus there will be
no damage due to the redaction of the heat transfer. The concentrated brine is
collected and delivered
to disposal or to multi stage evaporator to recover most of the water and
generates a ZLD (Zero Liquid
discharge) system. The heat transfer surfaces between the steam and the
produced water will have to
be clean or the produced water will have to be treated. The concentrated
brine, possibly with organics,
will be treated in a low pressure, low temperature evaporator to increase
their concentration; the
higher the concentration is, the lower the temperature. In my application, due
to the direct approach of
the heat transfer, the system in ZLD with the highest concentration, possibly
up to 100% liquid recovery
while generating solid waste, is at the first stage at the higher temperature
due to the direct mixture
with the superheated dry steam that converts the liquid into gas and solids.
[08] US patent No. 7,591,309 issued to Minnich et al. on September 22, 2009
describes the
use of steam for operating a pressurized evaporation facility where the
pressurized vapor steam is
injected into underground formation for EOR. The steam heats the brine water
which is boiled to
generate additional steam. To prevent the generation of solids in the
pressurized evaporator, the
internal surfaces are kept wet by liquid water and the water is pre-treated to
prevent solid build up. The
concentrated brine is discharged for disposal or for further treatment in a
separate facility to achieve a
ZLD system. To achieve ZLD, the brine evaporates in a series of low pressure
evaporators (Multi Effect
Evaporator).
[09] US patent No. 6,733636, issued to Heins on May 11, 2004, describes a
produced water
treatment process with a vertical MVC evaporator.
[10] US Patent No. 7,578,354, issued to Minnich et al. on August 25, 2009,
describes the use
of MED for generating steam for injecting into an underground formation.
[11] US Patent No. 7,591,311, issued to Minnich et al. on September 22, 2009,
describes
evaporating water to produce distilled water and brine discharge, feeding the
distilled water to a boiler,
and injecting the boiler blow-down water from the boiler to the produced
steam. The solids and possibly
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volatile organic remains are carried with the steam to the underground oil
formation. The concentrated
brine is discharged in liquid form.
[12] This invention's method and system for producing steam for extraction of
heavy
bitumen includes the steps as described in the patent figures.
[13] The advantage and objective of the present invention are described in the
patent
application and in the attached figures.
[14] These and other objectives and advantages of the present invention will
become
apparent from a reading of the attached specifications and appended claims.
SUMMARY OF THE INVENTION
[15] The method and system of the present invention for steam production for
extraction of
heavy bitumen by injecting the steam to an underground formation or by using
it as part of an above
ground oil extraction facility includes the following steps: (1) Generating a
super heated steam stream.
The steam is generated by a commercially available non-direct steam generation
facility , possibly as
part of a power plant facility; (2) Using the generated steam as the hot gas
to operate a DCSG (Direct
Contact Steam Generator); (3) Mixing the super heated steam gas with liquid
water with significant
levels of solids, oil contamination and other contaminate; (4) Directly
converting liquid phase water into
gas phase steam; (5) Removing the solid contaminates that were supplied with
the water for disposal or
further treatment; (6) Using the generated steam for EOR, possibly by
injecting the produced steam into
an underground oil formation through SAGD or CSS steam injection well.
[16] In another embodiment, the invention can include the following steps: (1)
Generating a
super heated steam stream. The steam is generated by heating a steam stream in
non-direct heat
exchanger; (2) Using the generated steam as the hot gas to operate a DCSG
(Direct Contact Steam
Generator); (3) Mixing the super heated steam gas with liquid water with
significant levels of solids, oil
contamination and other contaminates; (4) Directly converting liquid phase
water into gas phase steam;
(5) Removing the solid contaminates that were supplied with the water for
disposal or further
treatment; (6) Recycling a portion of the generated steam back to the heating
process of (1) to be used
as hot gas operating the DCSG. The recycled steam can be cleaned to remove
contaminates that can
affect the heating process (like silica). The cleaning process can include any
type of filter, precipitators
or wet scrubbers. Chemicals (like caustic, magnesium salts or any other
commercially available
chemicals) can be added to the wet scrubber to remove contaminates from the
steam flow.
CA 02748477 2011-08-02
[17] In another embodiment, part of the generating steam is condensed and used
to wash
the produced steam from solid particles in a wet scrubber. Chemicals can be
added to the liquid water
to remove contaminates. A portion of the liquid water is recycled back and
mixed with the superheated
steam to transfer it into gas and solids. A portion from the scrubbed
saturated steam flow can be
recycled and heated to generate a super heated "dry" steam flow to drive the
SD-DCSG and change the
liquid flow into steam.
[18] In another embodiment, the scrubbed saturated steam, after the solids
were removed,
can be condensed to generate contaminate free liquid water, at a saturated
temperature and pressure.
The liquid water can be pumped and fed into a commercially available non-
direct steam boiler for
generating super heated steam to drive the SD-DCSG for transferring the liquid
contaminated water into
gas and solids.
[19] In another embodiment, the SD-DCSG is integrated with DCSG that uses
combustion
gases as the heat source. In that embodiment, the discharge from the SD-DCSG
can be in a liquid form
and it can be used as the water source for the combustion gas driven DCSG.
[20] The present invention can be used to treat contaminated water by SD-DCSG
in different
industries like the power industry or chemical industry where there is a need
to recover the water from
contaminated water stream to generate steam with zero liquid discharge.
[21] The system and method different aspects of the present invention are
clear from the
following figures.
DETAILED DESCRIPTION OF THE DRAWINGS
[22] FIGURES 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the method
and the
system.
[23] FIGURE 2 shows a block diagram of the invention. Flow 9 is superheated
steam. The
steam pressure can be from 1 to 150 bar and the temperature can be between
150C and 600C. The
steam flows to enclosure 11 which is a SD-DCSG. Contaminated produced water 7,
possibly with organic
contaminates, suspended and dissolved solids, is also injected into enclosure
11 as the water source for
generating steam. The water 7 evaporates and is transferred into steam. The
remaining solids 12 are
removed from the system. The generated steam 8 is at the same pressure as that
of the drive steam 9
but at a lower temperature as a portion of its energy was used to drive the
liquid water 7 through a
phase change. The generated steam is also at a temperature that is close to
the saturated temperature
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of the steam at the pressure inside enclosure 11. The produce steam can be
further treated 13 to
remove carry-on solids, reducing its pressure and possibly removing additional
chemical contaminates.
Then the produced steam is injected into an injection well for EOR.
[24] FIGURE 2A shows a schematic of a vertical SD-DCSG. Dry steam 9 is
injected to vessel 11
at its lower section. At the upper section, water 7 is injected 3 directly
into the up-flow stream of dry
steam. The water evaporates and is converted to steam at lower temperature but
at the same pressure.
Contaminates that were carried on with the water are turned into solids and
possibly gas (if the water
includes hydrocarbons like naphtha). The produced gas, mainly steam, is
discharged from the SD-DCSG
at the top. To prevent carried-on water droplets, demister packing 5 can be
used at the top of SD-DCSG
enclosure 11. The solids 12 are removed from the system from the bottom 1 of
the vertical enclosure
where they can be disposed of or further treated.
[25] FIGURE 2B shows a block diagram of the invention. This figure is similar
to Figure 2 but
with an additional solids removal system as described in Block 15. Block 15
can include any commercially
available Solid - Gas separation unit. In this particular figure, cyclone
separator 19 and electrostatic
separation are presented. High temperature filters, that can withstand the
steam temperature, possibly
with a back-pressure cleanup system, can be used as well. The steam flow
leaving the SD-DCSG can
include solids from the contaminate water 7. A portion of the solids 12 can be
recovered in a dry or wet
form from the bottom of the steam generation enclosure 11. The carry-on solids
14 can be recovered
from the gas flow 8 in a dry form for disposal or for further treatment.
[26] FIGURE 2C is another embodiment of a reaction chamber apparatus of a high-
pressure
steam drive direct contact steam generator of the present invention. A similar
structure can be used
with DCSG that uses combustion gas as the heat source to convert the liquid
water into steam. A
counter-flow horizontally-sloped pressure drum 10 is partially filled with
chains 11 that are free to move
inside the drum and are internally connected to the drum wall. A parallel flow
design can be used as
well. The chains increase the heat transfer and removes solids build-up. Any
other design that includes
internal embodiments that are free to move or moving with the rotating
enclosure and lifting solids and
liquids to enhance their mixture with the flowing gas can be used as well. The
drum 10 is a pressure
vessel and is continually rotating, or rotating at intervals. At a low point
of the sloped vessel 10, hot dry
steam 8 is generated by a separate unit, like the pressurized boiler (not
shown), and is injected into the
enclosure 8. The boiler is a commercially available boiler that can burn any
available fuel like coal, coke,
or hydrocarbons such as untreated heavy low quality crude oil, VR (vacuum
residuals), asphaltin, coke,
or any other available carbon or hydrocarbon fuel. The pressure inside the
rotating drum can vary
CA 02748477 2011-08-02
between lbar and 100bar, according to the oil underground formation. The
vessel is partially filled with
chains 10 that are internally connected to the vessel wall and are free to
move. The chains 10 provide an
exposed regenerated surface area that works as a heat exchanger and
continually cleans the insides of
the rotating vessel. The injected steam temperature can be any temperature
that the boiler can supply,
typically in the range of 200C and 800C. Low quality water, like mature
tailing pond water, rich with
solids and other contaminants (like oil based organics) or contaminated water
from the produced water
treatment process are injected into the opposite higher side of the vessel at
section 4 where they are
mixed with the driving dry steam and converted into steam at a lower
temperature. This heat exchange
and phase exchange continues at section 3 where the heavy liquids and solids
move downwards,
directly opposite to the driving steam flow. The driving steam injected at
section 2, which is located at
the lower side of the sloped vessel, moves upwards while converting liquid
water to gas. The heat
exchange between the dry driving steam to the liquids is increased by the use
of chains that maintain
close contact, both with the hot steam and with the liquids at the bottom of
the rotating vessel. The
amount of injected water is controlled to produce steam in which the dissolved
solids become dry or
high solids concentration slurry and most of the liquids become gases.
Additional chemical materials
can be added to the reaction, preferably with any injected water. The
rotational movement regenerates
the internal surface area by mobilizing the solids to the discharged point.
The heat transfer in section 3
is sufficient to provide a homogenous mixture of gas steam and ground - up
solids or high viscosity
slurry. Most of the remaining liquid transitions to gas and the remaining
solids are moved to a discharge
point 7 at the lower internal section of the rotating vessel near the rotating
pressurized drum 10 wall.
The solids or slurry are released from the vessel 10 at a high temperature and
pressure. They undergo
further processing, such as separation and disposal.
[27] FIGURE 2D shows a schematic of a vertical SD-DCSG. It is similar to Fig.
2A with the
following changes. Vessel 11 includes a liquid water 1 bath at its bottom. The
water maintained at a
saturated temperature. Saturated water is recycled and dispersed 3 into the up-
flow flow of dry steam
9. The dispersed water evaporated into the up-flowing steam. Contaminates that
were carried on with
the water are turned into solids and possibly gas (if the water includes
hydrocarbons). The produced
gas, mainly steam, is discharged from the SD-DCSG at the top. Portion of the
saturated water 1
dispersed at the up-flow stream of dry steam. The water evaporates converted
to a lower temperature
steam. Solids are curried with the up-flow gas B. Over-sized solids 12 can be
removed from the system
from the bottom 1 of the vertical enclosure in a slurry form for further
treatment.
CA 02748477 2011-08-02
[281 FIGURE 2E shows a schematic of a SD-DCSG integrated into an open mine
oilsands
extraction plant for generating the hot extraction water while consuming the
Fine Tailing generated by
the extraction process. . Flow 9 is superheated steam. The steam flows to
enclosure 11 which is a SD-
DCSG. Fine Tailings (FT) contaminated produced water 7, is also injected into
enclosure 11 as the water
source for generating steam. The water component in 7 evaporates and is
transferred into steam. The
remaining solids 12 are removed from the system. The generated steam 8 is at
the same pressure as
that of the drive steam 9 but at a lower temperature as a portion of its
energy was used to drive the
liquid water 7 through a phase change. The generated steam is also at a
temperature that is close to (or
slightly higher from) the saturated temperature of the steam at the pressure
inside enclosure 11. The
produce steam is fed into a heat exchanger / condenser 13. In figure 2E, a non-
direct heat exchanger is
described. A direct heat exchanger can be used as well. The produced steam
condensation energy is
used to heat the flow of cold extraction process water 52 to generate a hot
process water 52A flow at
temperature of 70-90C. The produced hot process water can be used in Block A
for tarsands extraction.
The hot condensate 10 that is generated from steam flow 8 can be added to the
process water 52A or
use for other usage as a water source for High Pressure steam boiler, as an
example. In case that NCG
were generated 17, they are recovered for further use. (For FT 9 that contains
low levels of organics, low
amounts of NCG will be generated. With the use of direct contact heat exchange
between the process
water 52 and the produced steam 8 at 13 (not shown), the low levels of NCG
will be dissolved and
washed by the large amount of process water 14). Block A is a typical open
mine extraction oilsands
plant as described, for example in Block 5 in Figure 8. Flow 7 is fine
tailings generated during the
extraction process. Flow 14 is additional fine tailings from other sources,
like MFT from a tailing pond
(not shown). The driving steam 9 can be generated by compressing and heating a
portion of the
generated steam as described in Figure 3 (not shown).
[29] FIGURE 2F shows a SD-DCSG with a non-direct heat exchanger to heat the
process
water and with the combustion of the NCG hydrocarbons as part of generating
the driving steam. Fine
tailings or MFT 7 are injected to a SD-DCDG. In figure2F a vertical fluid bed
SD-DCSG is schematically
presented. Any other SD-DCSG can be used as well like the horizontal SD-DCDG
presented in Figures 3A,
3B, 3C or any other design. The FT 7 is mixed with dry super-heated steam flow
9 that is used as the
energy source to transfer the liquid water phase in flow 7 to gas (steam)
phase by direct contact heat
exchange. The FT 7 solids removed in a stable form 12 where they can be
economically disposed and
support traffic. The produced steam 8 is condensed in a non-direct heat
exchanger / condenser 13. The
water condensation heat is used to heat the extraction process water 14. With
some tailings types, NCG
CA 02748477 2011-08-02
(Non Condense Gas) 17 are generated due to the presents of hydrocarbons like
solvents used in the
froth treatment or oil remains that were not separated and remained with the
tailings. The NCG 17 is
burned together with other fuel 20, like natural gas, syngas or any other
fuel. The combustion heat is
used, through non-direct heat exchange, to produce the superheated driving
steam 9 used to drive the
process. The amount of energy in the NCG hydrocarbon 17 recovered from typical
oilsands tailings, even
from a solvent froth treatment process, is not sufficient to generate the
steam 9 to drive the SD-DCSG. It
can provide only a small portion from the process heat energy used to generate
the driving steam 9.
One option is to use a standard boiler 18 design to generate steam from liquid
water feed 19 from a
separate source. Another option is to use portion of the produced steam
condensate 23 as the liquid
water feed to generate the driving steam 9. The condensate will be treated to
bring it to a BFW quality.
Treatment units 24 are commercially available. Another option to generate the
driving steam 9 is to
recycle portion of the produced steam 8. The recycled produced steam 21 is
compressed 22. The
compression is needed to overcome the pressure drop due to the recycle flow
and generate the flow
through the heater 18 and the SD-DCSG 11. The compression can be done using
steam ejector with high
pressure additional steam or with the use of any available low pressure
difference mechanical
compressor. The recycled produce steam 21, possibly after additional cleaning,
like wet scrubbing, to
remove contaminates like silica, is indirectly heated by combustion heater 18.
[30] FIGURE 3 is an illustration of one embodiment of the present invention
without using an
external water source for the driving steam. SD-DCSG 30 includes a hot and dry
steam injection 36. The
steam is flowing upwards where low quality water 34 is injected to the up flow
steam. At least a portion
of the injected water is converted into steam at a lower temperature and at
the same pressure as the
dry driving steam 36. The generated steam can be saturated ("wet") steam at a
lower temperature than
the driving steam. A portion of the generated steam 32 is recycled through
compressing device 39. The
compression is only designed to create the steam flow through heat exchanger
38 and create the up
flow in the SD-DCSG 30. The compressing unit 39 can be a mechanical rotating
compressor. Another
option is to use high pressure steam 40 and inject it through ejectors to
generate the required over
pressure and flow in line 36. Any other commercial available unit to create
the recycle flow 36 can be
used as well. The produced steam, after its pressure slightly increased to
generate the recycle flow 36,
and possibly after contaminates are removed in a dry separator or wet scrubber
to protect the heater,
flows to heat exchanger 38 where additional heat is added to the recycled
steam flow 32 to generate a
heated "dry" steam 36. This steam is used to drive the SD-DCSG as it is
injected into its lower section 30
and the excess heat energy is used to evaporate the injected water and
generate additional steam 31.
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The heat exchanger 38 is not a boiler as the feed is in gas phase (steam).
There are several commercial
options and design to supply the heat 37 to the process. The produced steam 31
or just the recycled
produced steam 32 can be cleaned from solids carried with the steam gas by an
additional commercially
available system (not shown). The system can include solid removal; this heat
exchanger can be any
commercially available design. The heat source can be fuel combustion where
the heat transfer can be
radiation, convection or both. Another possibility can be to use the design of
the re-heat heat exchanger
typically used in power station boilers to heat the medium / low pressure
steam after it is released from
the high pressure stages of the steam turbine. This option is schematically
Shawn on figure 3. Typically,
the re-heater 40 supplies the heat to operate the second stage (low pressure)
steam turbine.
Accordingly the feed to re-heater is saturated or close to saturated medium-
low steam. As such,
minimizing the re-heater design conversion changes to heat the generated steam
31 for generating the
superheated steam 36. If an existing stem power plant is used, the
supercritical high-pressure steam can
be used to drive a high pressure steam turbine, while the remain heat can be
used through the re-
heater to provide the heat 37 to drive the steam generation facility. A high
pressure steam turbine has
smaller dimensions and TIC (Total Installed Cost) compared to medium / low
pressure steam turbine per
energy unit output.
[31] FIGURE 3A is an illustration of one embodiment of the present invention.
It is similar to
Figure 3 with the use of a rotating SD-DCSG. The driving superheated ("dry")
steam 36 is injected into
rotating pressurized enclosure 30. The rotating SD-DCSG enclosure consumes
liquid water 34, possibly
with solid and organic contaminations, and generates lower temperature steam
31 and solid waste 35
that can be disposed in a landfill and support traffic. The rotating SD-DCSG
30 is described in Figure 2C.
[32] FIGURE 3B is an illustration of a parallel flow SD-DCSG. It is similar to
Figure 3A with the
use of a parallel flow direct contact heat exchange between the liquid water
and the fry steam. The
driving superheated ("dry") steam 36 is injected into rotating pressurized
enclosure 30. Liquid water 34,
possibly with solid and organic contaminations, is injected together with the
driving steam at the same
side of the enclosure. Lower temperature produced steam 31 and solid waste 35
that can be disposed in
a landfill and support traffic. The driving superheated steam is generated by
recycling portion of the
produced steam 32. The recycled produced steam is compressed to overcome the
pressure loss and
generate the floe. It is non-directly heated 38 and recycled back 36 to the SD-
DCDG 30.
[33] FIGURE 3C is an illustration of a SD-DCSG with stationary enclosure and
an internal
rotating element. Super heated driving steam 36 is injected into enclosure 30.
Low quality liquid water
with high levels of contaminates like Fine Tailings generated by an open mine
oilsands extraction plant,
CA 02748477 2011-08-02
are injected to the enclosure. The enclosure is pressurized. The liquid water
evaporated to generate
produced steam 33. The produced steam 33 is at a lower temperature compared to
the superheated
driving steam as it is close to the saturated point due to the additional
water that were evaporate and
converted to steam. The solids that were introduced with the low quality
liquid water 34 removed in a
stable form where they can be disposed of in a land fill and support traffic.
To increase the direct
contact heat transfer within the enclosure 30, a moving internals are used.
The internals can be any
commercial available design that is used to mobilized slurry and solids in a
cylindrical enclosure. A
rotating screw 31 can be used. The rotating movement 32 is provided through a
pressure sealed
connection from outside the enclosure. The screw mobilized the solids and
drives them to the discharge
location where they are discharged from the pressurized enclosure.
[34) FIGURE 3D is an illustration of a modification of figure 3C and 3B for a
steam drive Non-
Direct contact steam generator where the heat supplied by steam to a heated
stationary external
enclosure and an internal rotating element to mobilize the evaporating low
quality solids rich water, like
MFT and the solids . The process includes generating or heating steam 36
through indirect heat
exchange (not shown). Using the generated steam energy 36 to indirectly gasify
liquid water 34 with
solids and organic contaminated, like fine tailings, so as to transfer said
liquid water from a liquid phase
to a gas phase 33. Removing solids 35 to produce solids free gas phase steam
33. The produced steam
can be further condensed to generate heat and water for oil production (not
shown). The hot driving
steam (there is no need in using dry superheated steam as the driving steam)
36 is heating enclosure 30.
Low quality liquid water with high levels of contaminates like Fine Tailings
generated by an open mine
oilsands extraction plant, are injected to the enclosure. The enclosure is
pressurized. The liquid water
evaporated due to non-direct heat transfer from the enclosure 30 to generate
produced steam 33. The
solids that were introduced with the low quality liquid water 34 removed in a
stable form 35 where they
can be disposed of in a land fill and support traffic. To increase the direct
contact heat transfer within
the enclosure 30 and to mobilize the solids and slurry, a moving internals are
used. The internals can be
any commercial available design that is used to mobilized slurry and solids in
a cylindrical enclosure. A
rotating screw 31 can be used. The rotating movement 32 is provided through a
pressure sealed
connection from outside the enclosure. The screw mobilized the solids and
drives them to the discharge
location where they are discharged from the pressurized enclosure. Any other
design (like double screw,
lifting scoops, chains) can be used as well. Condensed water 36A from the
condensing driving steam 36
is recycled where it can be re-heated for generating additional driving steam
36 or for any other use.
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[35] Figure 3E shows a parallel flow and a counter flow steam drive direct
contact steam
generation system. In the parallel flow system 1 liquid water 7, possibly with
high level of suspended
and dissolved solids like fine tailings, produced water, evaporator brine,
brackish water, produced gas,
carbons, hydrocarbons or any available water feed possible with high levels of
contaminates is fed into a
longitude enclosure 5. Superheated dry steam 6 is also fed into the same
longitude enclosure 4 at the
same side where the low quality water is injected where the two flows, the
liquid and the gas are mixed
in direct contact. To enhance the mixing and mobilize the generated slurry or
solids a mechanical energy
is supplied into the enclosure. A possible simple way to supply the mechanical
energy is by a longitude
rotating element 9. There are several designs for such a rotating element that
can includes spiral,
scoops, scrapers or any other commercial available design. It is possible to
use a single rotating unit 11
in a circle enclosure 10. It is also possible to use double rotating units 13
and 14 in an oval enclosure 12
where the multiple rotating units can enhance the mixing and the removal of
solids deposits. In the
parallel system, the produced steam 3 is discharged with the solids rich
slurry or solids at the enclosure
end. To allow efficient heat transfer duration, the enclosure length is longer
than its diameter, typically
the length L is at least twice the diameter D. The steam-solids mixture is
further separated (not shown).
In the counter flow system 15 the low quality liquid flow 18, similar to flow
7 in the parallel flow system
1, is fed to a longitude enclosure with internal rotating element to introduce
mechanical energy to the
enclosure. The superheated driving steam 16 is introduced at the opposite end
of the enclosure where it
is mixed with the flow of liquids 18. The heat energy in the super heated
driving steaml6 is directly
transferred to the liquid water to generate steam. The slurry or solids are
transferred by rotating auger,
possibly with spiral in an opposite direction to the driving steam 16 flow and
discharged from the
longitude system at 17. It is also possible to connect the parallel flow and
the counter flow systems to
each other where the discharge from the first system 3 or 17 still contains
significant levels of liquids,
possible in a slurry form, is fed into the second system 18 or 7.
[36] Figure 3F shows a direct contact steam generating system as shown in
Figure 3E with
solids separation. The direct contact parallel flow steam generator 1 is
similar to figure 3E where the
solid contaminates are removed from the steam flow in a separator 10 through
de-pressurized
collection hopper system that includes valves 12 and 14, de-pressurized
enclosure 13, and solids
discharge 15. The enclosure 10 can include internals to generate cyclone
separation or any other
commercial available solids separation design. A commercial available gas-
solid separation packages
can be added to the discharged flow 20 to remove solids from the gas stream
(not shown). The solids
removed from stream 20 can be discharged through the de-pressurized hopper
system 13.
CA 02748477 2011-08-02
[37] FIGURE 3G is a steam drive direct contact steam generator apparatus. It
includes a
vertical enclosure 2 with steam injection points 6 arranged around the
enclosure wall. The injection
flows 5, 9 are arranged to enhance the mixing flow within the vessel and to
protect the enclosure wall
from solids build-ups Water. Liquid water 7 injected into the upper section 1
of the enclosure. The water
injection can include a sprayer to disperse the water and enhance the mixture
between the liquid water
and the steam. The injected water can be low quality produced water or water
from any other source,
like tailings pond water. The injected water 7 can include dissolve or
suspended solids as well as any
other carbon or hydrocarbon contamination. The water is injected at the upper
section - section C.
Super heated dry steam 5 is injected at section B located below the water
injection 7. The dry steam
injected substantially perpendicular to the enclosure wall, possibly with an
angle to enhance the mixture
of the liquid water and the steam and to minimize the contact between the
liquid water and the
enclosure wall to prevent solids deposits build up on the enclosure wall. The
solids rich contaminates 4,
that were introduced to the system with the water feed 7, after most of the
liquid water evaporates into
steam, are collected at the bottom of the enclosure 3 and removed from the
system. The injected steam
9 can be disperse by a nozzle 10 close to the enclosure wall in a way that
part of the steam flow will be
spread and generate a flowing movement that will reduce the potential contact
between the water feed
7 and the enclosure wall. The injected steam 5 and the water feed that was
converted to steam is
released in a gas flow 8 from the upper section of the enclosure 1. The steam
flow 8 can flow through a
demister and a separator that can be located internally in section C or
externally to remove water
droplets and solids remains (not shown). The pressure of the produced steam 8
is substantially similar to
the pressure of the superheated driving steam 5, except from a small
difference to generate the up flow
movement, and its temperature is closer to the saturated temperature at the
particular enclosure
pressure due to the evaporation of the feed water 7.
[38] FIGURE 3H is another configuration of a steam drive direct contact steam
generator
apparatus. Sections A and B are described in Figure 3E. Superheated dry steam
6 is injected into section
B. Any liquid water that flows into the up-flow chamber of section B is
converted into steam.
Contaminates, mainly solids, that were carried with the feed water 3 are
removed from the bottom of
the enclosure 9 from section A. The superheated steam 6 flows from section B
into section C located
above B. Section C include a fluid bed 4. This fluid bed includes liquid,
solids and slurry supplied with the
feed water 3. Additional free moving bodies, like sand, found metal particle,
round ceramic particle can
add to the fluid bed 4 to enhance the heat transfer between the up flowing
steam and the slurry from
the water feed 3. The fluid bed section C can include additional steam
injectors (not shown) to mobilize
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the solids and prevent solids build-ups that can block the fluid bed. A direct
steam injection into section
C can be done in intervals in strong bursts to mobilize the fluid bed and
remove build-ups. Mechanical
means to create movement within the fluid bed can be used as well, possibly in
intervals, in case that
the steam up flow from section B is not sufficient to prevent solidifications
area within the fluid bed 4
and remove build-ups (not shown). Solids can also be removed directly from 4,
from the fluid bed
section. The produced steam 1 from water flow 3 and from the driving super
heated steam 6 is used for
oil extraction or for other usages. In the case that the low quality water
feed 3 contains hydrocarbons,
portion of the hydrocarbons will be recovered with the produced steam and
injected into the
underground formation for heavy oil recovery. The produced steam 1 can be
further treated in
commercially available demister and gas-solids separator to remove water
droplets or flying solids
carried-on with the generated steam flow.
[39] FIGURE 31 is a steam drive direct contact steam generator apparatus.
Superheated
steam 7 is injected to a vertical enclosure at its lower section. Liquid water
3 is injected into the
enclosure above the steam injection area. The water injection can include
sprayer to disperse the water
and enhance the mixture between the liquid water 3 and the steam 7. The
injected water can be low
quality SAGD produced water, boiler blow-down, evaporator brine or water from
any other source, like
open mine tailings pond water. The injected water 3 can include dissolve or
suspended solids as well as
any other carbon or hydrocarbon contamination. To enhance the mixture of the
steam and the water
and to remove solids an internal structure 4 is placed in between the steam
injection section and the
water injection section. Internal 4 can include a moving bed or any other
configuration of free moving
elements, like chains 5 that can remove solids build-ups from the supplied
water 3. Mechanical energy
can be introduced into the internal structure 4 to generate continues or
interval movement between its
parts or between the internal structure to the enclosure. Vibration movement
can be introduced to the
bottom structure 6 to prevent solids build-ups. The solids 9 are collected and
removed from a cone 8 in
the enclosure bottom. One option is to generate a relative movement between
the upper bed structure
4 and the lower bed structure 6 and the enclosure wall. Any commercial
available design for a moving
bed internals can be used as well. The generated steam 2 is released from the
upper section of the
enclosure 2. The generated steam 1, can be further cleaned in a dry or wet
scrubber and used in
enhanced oil recovery by injection it underground, like in SAGD or CSS or to
heat water in an open mine
extraction process.
[40] FIGURE 3J is a steam drive direct contact steam generator with internal
wet scrubber
that generates additional wet solids free steam. Superheated steam 10 is
injected into section A of
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vertical enclosure. Liquid water 5 is injected and dispersed above the dry
steam injection point. A fluid
bed, possibly with additional solid particles 9 is supported above the steam
injection area 10 in section
A. The fluid bed is increasing the heat transfer between the up-flowing steam
10 and the dispersed
water 5. Solids 12 are remove from the bottom of section A for disposal or
further treatment. The
bottom section of the fluid bed can move by mechanical means to generate
moving or vibrating bed.
Solids can recover from the fluid bed at section A to maintain a constant
solids level. The up-flow
generated steam, possibly with solids particles, is flowing to section B. In
this section the up flowing
steam is scrubbed by liquid saturated water 7. To generate the contact between
the liquid saturated
water and the steam a liquid bath 7 can be used where the steam is forced (due
to pressure differences)
through the liquid water. Another option is to continually recycle hot
saturated liquid water 4 and spray
them at 2 into the up flowing steam, by that scrubbing any solids remains and
generating additional
steam. In Fig. J both options are presented (the liquid bath combined with the
water sprayers 2)
however it is possible to use only one of the presented options. If only
liquid bath 7 is used, the feed
water 3 will be supplied to the liquid bath as a make-up water (not shown) to
replace the water that was
evaporated in section B and water 5, with any solids scrubbed, from section B
that is supplied to section
A and evaporated there. The generated solids free saturated steam from section
B is flowing into section
C. Section C can include a demister to separate any droplets carried on with
the up-flow steam (not
shown). The produced solids free steam can be used for oilsands bitumen
recovery with any commercial
oilsands plant that required steam.
[41) FIGURE 3K is an illustration of one embodiment of the present invention.
An up-flow
direct contact steam generator, as described in Figure 3H or 31 is used to
generate steam 9 from
superheated steam and liquid water 8. Additional designs for direct contact
steam generators, like
Figure 2C, 2D and 2E can be used as well. The produced steam 9 is flowing to
an external wet scrubber
that also generates additional steam. The produced steam is mixed with liquid
water 11, possibly by
circulating system 12 with sprayers for dispersing the water 3, where any
solids remains are scrubbed
with the water droplets while wet steam is generated. Liquid water 8 at
saturate temperature and
pressure continually recycled and injected into the steam generator 2. Water
feed, possible with high
levels of contaminates, is feed into the system. Portion 14 from the produced
steam 13 is used for any
industrial usage, like for oil recover or for steam use in the chemical
industry. The other portion 15 of
the produced steam is recycled and used to produce dry superheated steam 24 to
operate the direct
contact steam generator 1. The recycled produced steam 15 can be further
filtered in any commercial
available filter packages to remove contaminates like gas silica remains.
Water and chemicals 17 can be
CA 02748477 2011-08-02
used in any gas treated commercial package 16. The steam 19 is then compressed
to recover the
pressure drops in the recycled piping and equipment and flow to steam heater.
Depend on the
mechanical compressing system 20 requirements, some heat can be added to flow
19 prior to the
compression. Another option is to use a steam ejector in 20 with high pressure
steam feed to generate
the recycle flow 21. The steam flow 21 is further heated in any commercial
available heating system 23.
Heat flow 22 increases the steam temperature 24 to generate a dry, superheated
steam flow that is
injected back to direct contact steam generator as the driving steam.
[42] FIGURE 4 is an illustration of one embodiment of the present invention,
where the
generated steam 44 is saturated and is washed by saturated water in a wet
scrubber 40 where
additional steam is generated. BLOCK 1 includes the system as described in
FIGURE 3 where BLOCK 32
can include solid removal as means to remove solid particles from the gas
(steam) flow. BLOCK 3
generates steam 33 and stable waste 35. The generated steam 33 can contain
carry-on solid particles
and contaminates that might create problems of corrosion or solids build ups
in the high temperature
heat exchanger. One way to remove the solid contaminates is by a commercially
available solid-gas
separation unit, as described in Figure 2B or with any other prior art solids
removal method. However,
there is an advantage to wet scrubbing of solids and possible other gas
contaminates. To improve the
removal of the solids and other contaminates, the steam 33 is directed to a
wet scrubber. In one
embodiment, the wet scrubber generates the liquid water for its operation.
This is done by an internal
heat exchanger that recovers heat from the steam and generates condensate
water. The condensate
liquid water is used for scrubbing the flowing steam in vessel 40. The
condensate is recycled 41 and used
to wash the steam and is used as a means to improve the heat transfer. Low
quality water from the oil-
water separation process, fine tailing water from tailing pond or from any
other source is pre-heated
through heat exchanger 42 while recovering heat from the produced steam 34
generated by the SD-
DCSG 30. The condensate is recycled in the wet scrubber to wash the steam.
Additional chemicals can
be added to the condensate to remove gas contaminates. A portion of the
condensate with the solids
and other contaminates 43 is removed from vessel 40 to maintain the
contamination concentration of
the condensate constant. Additional low quality water 47A can be added to the
SD-DCSG without pre-
heating as to prevent excessive cooling of the produced steam 33 and the
generation of excessive
condensate. The generated steam after going through the wet scrubber is clean
and saturated ("wet")
steam. A portion of the clean steam 45 is directed through trough heat
exchange 38 to generate "dry"
steam to drive the SD-DCSG 30 with sufficient thermal energy to convert the
low quality water feed 34
into steam. The flow through the heat exchanger and inside the vessel 30 is
generated by any suitable
CA 02748477 2011-08-02
commercial unit that can be driven by mechanical energy or a jet energy driven
compression unit. The
produced clean saturated steam 46 can be injected into an underground
reservoir, like SAGD, for oil
recovery, it can also be used for heating process water for tar separation or
for any other process that
consumes steam.
[43] FIGURE 5 is a schematic diagram of one embodiment of the invention that
generates
wet scrubbed, clean saturated steam. BLOCK 1 includes a SD-DCSG 30 as
previously described. The
generated steam 31 can be cleaned from solids in commercially unit 32,
previously described. Low
quality water 34, like MFT (Mature Fine Tailings), produced water or water
from any other available
source can be injected to the SD-DCSG 30. Solids 35 carried by the water 34
are removed. The SD-DCSG
30 is driven by superheated ("dry") steam that supplies the energy needed for
the steam generation
process. The dry steam 36 is generated by a commercially available boiler as
described in BLOCK 4. BFW
(Boiler Feed Water) 49 is supplied to BLOCK 4 for generating the driving
steam. The boiler facility can
include an industrial boiler, OTSG, COGEN combined with gas turbine, steam
turbine discharge re heater
or any other commercially available design that can generate dry steam 36 that
can drive the SD-DCSG
30. In the case where the boiler consumes low quality fuel, like petcoke or
coal, commercially available
flue gas treatment will be used. There is a lot of prior art knowledge as for
the facility in BLOCK 4 as it is
similar to the facility that is used all over the world for generating
electricity. The generated steam from
the SD-DCSG 37 is supplied to BLOCK 2 that includes a wet scrubber. The wet
scrubber 50 can contain
chemicals like ammonia or any other chemical additives to remove contaminates.
The exact chemicals
and their concentration will be determined based on the particular
contaminates in the low quality
water that is used. The contamination levels are much lower than in direct
fired DCSG where the water
is directly exposed to the combustion products as described in my previous
patents. Liquid water 48 is
injected to the wet scrubber vessel 50 to scrub the contaminates from the up-
flowing steam 37. Liquid
water 51 that includes the scrubbed solids are removed from vessel 50 and
recycled back to the SD-
DCSG 30 together with the feed water 34. Depending on the particular feed
water quality 34, it can be
used in the scrubber. In that case stream 48 and 34 will have the same
chemical properties and be from
the same source. The scrubbed generated steam 45 generated at BLOCK 2 can be
used for extracting
and producing of heavy oil or for any other use.
[44] FIGURE 5A is an illustration of one embodiment of the invention where a
portion of the
driving steam water is internally generated. The embodiment is described in
Figure 5 with the following
changes: BLOCK 3 was added and connected to BLOCK 2. This block includes a
direct contact condenser /
heat exchanger 40 that is designed to generate hot (saturated) boiler feed
water 46 and possibly
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saturated steam 44. The saturated steam 45 from scrubber 50 flows into the
lower section of a direct
contact heat exchanger / condenser 40 where BFW 42 is injected. From the
direct contact during the
heat-up of the BFW, additional water will be condensed generating additional
BFW 46. A portion of the
injected and generated water 48 is used in wet scrubber 50 to remove
contamination and is then
recycled back to the SD-DCSG 30. The additional condensate, clean BFW quality
water 49, is used in
BLOCK 4 for generating steam. The condensate is hot at the water or steam
saturated temperature in
the particle system pressure. Addition hot condensate can be generated and
recovered from the system
as hot process water for oil recovery or for other uses. BLOCK 4 can include
any commercially available
steam generator boiler capable of producing dry steam 36. In Figure 5A a
schematic COGEN is described.
Gas turbine 62 generates electricity. The gas turbine flue gas heat is used to
generate or heat steam
through non-direct heat exchanger 61. Typically the produced steam is used to
operate steam turbines
as part from a combined cycle. At least part of the produces dry superheated
steam 36 is used to
operate the SD-DCSG 30.
[45] FIGURE 5B is a schematic view of the invention with internal distillation
water
production for the boiler. The illustration is similar to the process
described in Figure 5A with a different
BLOCK 3. The low quality water 47 is heated with the saturated clean (wet
scrubbed) steam 45 from
BLOCK 2 (previously described). The saturated steam 45 condenses on the heat
exchanger 42, located
inside vessel 40, while generating distilled water 46. A portion of the
distilled water 48 is recycled to the
wet scrubber vessel 50 where it removes the solids and generates additional
wet steam from the
partially dry steam generated in the SD-DCSG 30 in BLOCK 1. Additional
distilled water 49, possibly after
minor treatment and chemical additives (not shown) to bring it to BFW
specifications, is directed to the
boiler in BLOCK 4 for generating the driving steam. The system can produce
saturated steam 44A or
saturated liquid distilled water 44B or both. The produced steam and water are
used for oil production
and process or for any other use.
[46] FIGURE 5C is a schematic diagram of the method that is similar to Figure
5B but with a
different type of SD-DCSG in Block 1. Figure 5C includes a vertical stationary
SD-DCSG. The dry driving
steam 36 is fed into vessel 30 where the low quality water 34 is fed above it.
Due to excessive heat, the
liquid water is converted into steam. The waste discharge at the bottom 35 can
be in a liquid or solid
form. BLOCKS 2, 3 and 4 are similar to the previous Figure 513.
[47] FIGURE 6 is a schematic diagram of the present invention which includes a
SD-DCSG and
an FOR facility like SAGD for injecting steam underground. BLOCK 1 is a
standard commercially available
boiler facility. Fuel 1 and oxidizer 2 are combusted in the boiler 3. The
combustion heat is recovered
CA 02748477 2011-08-02
through non-direct steam generator for generation of superheated dry steam 9.
The combustion gases
are released to the atmosphere or for further treatment (like solid particles
removal, SOX removal, CO2
recovery etc.). The water that is fed to the boiler, is fed from BLOCK 2 which
includes a commercially
available boiler treatment facility. The quality of the supplied water is
according the particular
specifications of the steam generation system in use. The dry steam is fed to
SD-DCSG 10. Additional low
quality water 7 is fed into vessel 11 where the liquid water is transferred to
steam due to the excess
heat in the superheated driving steam 9. The generated steam 8, possibly
saturated or close to being
saturated steam, is injected into an underground formation through an
injection well 16 for EOR. The
produced emulsion 13 of water and bitumen is recovered at the production well
15. The produced
emulsion is treated using commercially available technology and facilities in
BLOCK 2, where the
bitumen is recovered and the water is treated for re-use as a BFW. Additional
make-up water 14,
possibly from water wells or from any other available water source can be
added and treated in the
water treatment plant. The water treatment plant produces two streams of water
- a BFW quality 6
stream as it is currently done to feed the boilers and another stream of
contaminated water 7 that can
include the chemicals that were used to produced the high quality BFW, oil
contaminates, dissolved
solid (like salts) and suspended solids (like silica and clay). The low
quality flow is fed to the SD-DCSG 10
to generate injection steam.
[48] FIGURE 6A is a schematic flow diagram of the integration between SD-DCSG
and DCSG
that uses the combustion gas generated by pressurized boiler. BLOCK 1 includes
a DCSG with non-direct
heat exchanger boiler as described in my previous applications. Carbon or
hydrocarbon fuel 2 is mixed
with an oxidizer that can be air, oxygen or oxygen enriched air 1 and
combusted in a pressurized
combustor. Low quality water 12 discharged from the SD-DCSG is fed into the
combustion unit to
recover a portion of the combustion heat and to generate a stream of steam and
combustion gas
mixture 4. The solid contaminates 18 are removed in a solid or stable slurry
form where they can be
disposed of. The steam and combustion gas mixture 4 is injected into injection
well 17 for EOR. Injection
well 17 can be a SAGD "old" injection well where the formation oil is partly
recovered and large
underground volumes are available, as well as where corrosion problems are not
so crucial as the well is
approaching the end of its service life. Another preferable option for using
the steam and combustion
gas mixture is to inject it into a formation that is losing pressure and needs
to be pressurized by the
injection of addition non-condensable gas, together with the steam. A portion
of the combustion
energy is used to generate superheated dry steam in a boiler type heat
exchanger 5. The generated
steam 9 is driving the SD-DCSG 10. The water for the non-direct boiler 5 is
supplied from the
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commercially available water treatment plant in BLOCK 2. Low quality water
from BLOCK 2 is fed directly
into the SD-DCSG where it is converted into steam. In this scheme, the
conversion is only partial as the
discharge from 10 is in a liquid form 12. The liquid discharge 12 is directed
to the combustion DCSG to
generate an overall ZLD (Zero Liquid Discharge) facility. The steam from the
SD-DCSG 8 is injected into
an underground formation through an injection well 16 for EOR.
[49] FIGURE 6B described a direct contact steam generator with rotating
internals, dry solids
separation and wet scrubber and saturated steam generator. Super heated
driving steam 13 is fed into
a direct contact steam generator where it is mixed with water, possibly with
contaminates. The
excessive heat energy in the steam evaporates the water to generate additional
steam. Solids 6 are
removed from the system in dry or slurry form. The produced steam is treated
in commercial available
gas treatment unit in block B. An inlet demister to removed carried-on liquid
droplets can be
incorporated in block B. Any commercial available unit to remove solids and
contaminates can be used
like cyclone solid removal system as schematically described in B1, a high
temperature filter B2, an
electrostatic precipitator B3 or combination with any other commercial
available design. The solids
removed in a dry form are added to the solids removed from the steam generator
14. The solids lean
flow 5 is fed into a saturated steam generator and a wet scrubber 2. Liquid
water recycled and dispersed
into the flowing steam. Portion from liquid water evaporates. The water
droplets remove contaminates.
Chemicals like anti-foaming, flocculants, Ph control and other commercial
available chemicals to control
the process efficiency and prevent corrosion can be added to the recycled
water 11. Make-up water 10
can be added to the system to replace the water converted to steam and the
recycled water with the
contaminates back to the feed water 13. The scrubbed solids free generated
steam 8 is supplied from
the system for other usages.
[50] FIGURE 6C includes SD-DCSG and heavy oil extraction through steam
injection. Emulsion
of steam, water bitumen and gas is produced from a production well 10, like a
SAGD well. The produced
flow 1 is separated in a separator 3 located in BLOCK A to generate water rich
flow 5 with contaminates
like sand, and hydrocarbons rich flow 4. There are few commercial designs for
separators that are
currently used by the industry. Chemicals can be added to the separation
process. The hydrocarbon rich
flow 4 is further treated in processing plant at BLOCK B. Flow 4 is furthered
separated into the produced
bitumen, usually diluted with light hydrocarbons to enhance the separation
process and to reduce the
viscosity to allow the flow of the bitumen in the transportation lines. In
block B the produced water that
remained with the flow 4 are de-oiled and used, usually with make-up water
from water wells, for
generated super-heated steam 6. The water rich flow 5, at a high temperature
that is close to the
CA 02748477 2011-08-02
produced emulsion temperature, is pumped into a SD-DCSG 7 where it is mixed
with the dry
superheated steam 6 to generate additional steam for injection 2. Light
hydrocarbons in flow 5
evaporate due to the heat to generate hydrocarbons that are injected with the
injection steam 2 to the
underground formation 11. It is known that hydrocarbons that are mixed with
the steam can improve
the oil recovery. The SD-DCSG 7 includes a rotating internals to enhance the
mixture between the two
phases and mobilized the generate slurry and solids. The solids 8 removed from
the system for landfill
disposal 13 or for any other use. The heat energy within flow 5 from separator
3 increase the quantity of
the steam generated in SD- DCSG 7 and by that improves the overall thermal
efficiency of the system.
The generated steam 2 is injected, possibly after additional contaminate
removal treatment and
pressure control (not shown), into an injection well 11 for EOR. The SD-DCSG 7
is a parallel flow steam
generator as described by unit 1 in figure 3E, however any other SD-DCSG
design like the counter flow
SD-DCSG as described by unit 15 in figure 3E, the rotating or fluid bed units
as described in drawings 2C,
2D and 3C-3J can be used as well.
[51] FIGURE 6D includes SD-DCSG similar to the system in 6C, where the
superheated driving
steam is generated by recycling and re-heating the produced steam generated by
the SD-DCSG 7. A
mixture of steam, water, bitumen and gas is produced from a production well
10, like a SAGD well. The
produced flow 1 is separated in a separator 3 located in BLOCK A to generate
water rich flow 5 and
hydrocarbons rich flow 4. There are few commercial design for separators that
are currently used by the
industry. Chemicals can be added to the separation process. The hydrocarbon
rich flow is further
treated in processing plant at BLOCK B. The water rich flow 5, possibly with
hydrocarbons and other
contaminates like sand is at a high temperature that is close to the produced
emulsion temperature. The
heat energy within flow 5 increase the quantity of the steam generated in SD-
DCSG 7 for a given
amount of superheated driving steam 6. Flow 5 is pumped into a SD-DCSG 7 where
it is mixed with dry
superheated steam 6 to generate additional steam 18. Any available design for
mixing the water and the
steam to generate additional steam and solids or slurry discharge can be used
as well. The solids or
slurry 8 removed from the system for landfill disposal 13 or for any other
use. The produced steam 18 is
split into two flows - flow 2 of the generated steam 18 is injected, possibly
after additional contaminate
removal treatment and pressure control (not shown), into an injection well 11
for EOR. The other part
from flow 18, flow 12, is recycled to BLOCK C. Depending on the recycled steam
quality and the feed
requirements of the compressing and heating units, it can be pre-cleaned by
any commercial available
cleaning technologies. The recycled produce steam is compressed by mechanical
compressor, steam
ejector or any other available units 14 and indirectly heated by heat flow 15
to generate a super heated
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driving steam flow 6. The heating can be done with any available heating unit
that can heat steam,
possibly with hydrocarbons remains. Electrical heaters for small units, carbon
(like coal, petcoke etc')
combustion units for large scale or hydrocarbon fired (like natural or
produced gas, bitumen etc') for
medium and large size units can be used as facility 16 for heating the
produced steam (possibly with
small amounts of hydrocarbon gas) to generate the dry, superheated driving
steam 6. The superheated
driving steam 6 is injected to the SD-DCSG 7 where it is mixed with the
produced water 5.
[52] FIGURE 6E is a schematic view of SD-DCSG with similarities to figure 6D
and with
external supplied make-up HP steam. A mixture of steam, water, bitumen and gas
is produced from a
production well 10, like a SAGD well. The produced flow 1 is separated in a
separator 3 located in BLOCK
A to generate water rich flow 5 and hydrocarbons rich flow 4. There are few
commercial designs for
separators that can be used. Chemicals can be added to the separation process.
The hydrocarbon rich
flow is further treated in commercial available oil and water processing plant
at BLOCK B. There are
commercial available technologies and designs for such plants where some are
used by the oilsands
thermal insitue industry (like SAGD processing plant). The water rich flow 5,
possibly with hydrocarbons
and other contaminates like sand is at a high temperature close to the
produced emulsion 1
temperature. Flow 5 is pumped into a SD-DCSG 7 where it is mixed with dry
superheated steam 6 to
generate additional steam 18. The SD-DCSG is a counter flow design as
described by unit 15 at figure 3E.
Any available design for mixing the water and the steam to generate additional
steam and solids rich
water can be used as well. The solids or slurry removed from the system
through separator 20 and de-
compression system 21 in a stable form 22. The produced steam 18 is split into
two flows - flow 2 of
the generated steam 18 is injected, possibly after additional contaminate
removal treatment and
pressure control (not shown), into an injection well 11 for FOR or for any
other usage in the mining or
any other industry that required large quantities of steam. The other part
from flow 18, flow 12, is
recycled to re-heat and use as the superheated driving steam. In non-direct
contact heater 16,
additional heat Q is added to the steam flow 12 to generate superheated dry
steam 13. The heating can
be done with any available heating facility. This superheated steam is
compressed with the pressure
energy from HP (High Pressure) make-up steam 6 generated in BLOCK B. The make
up steam is produced
from the produced water that remains in flow 4. The produced water is treated
in the process facility in
BLOCK B that includes de-oiled and possibly de-mineralized before used in
commercial available high
pressure boiler or OTSG for generating high pressure steam 6. Additional make-
up water 24 is usually
required to compensate for the water loss in the formation and for the waste
water rejected from the
water treatment facility in BLOCK B. The make-up water is usually supplied
from water well 25 or from
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any available water source. Disposal water 23 from the water processing
facility in BLOCK B, possibly
with oil and solids can be recycled to the SD-DCSG 7 together with stream 5 as
the water feed to 7.
[53) FIGURE 6F describes another embodiment of the present invention for
generating
steam for oil extraction with the use of steam boiler and steam heater. A
mixture 36 of steam, water,
bitumen and gas is produced from a production well 32, like a SAGD production
well. The produced flow
36 is separated in a separator 33 to separate the produced gas 38 from the
produced liquids 37. The
produced gas 38 can include reservoir gas, mainly light hydrocarbons and
possibly lifting gas, in case
lifting gas is used to lift the produced liquids to the surface (not shown).
The produced gas is used in the
process as lifting gas. It can also used as fuel for the boilers or for any
other used. The produced liquid
emulsion 37 is cooled in heat exchanger 34 while heating the boiler feed water
40 to generate pre-
heated boiler feed water. The cooled liquid mixture 39, after the produced gas
were already removed is
feed into separator 35. Chemicals, sometime with solvents like light
hydrocarbons, can be added to the
produced liquid 39 to support the separation process, break the emulsion and
prevent foaming. The
separation vessel 35 separates the water liquid 43 from the bitumen 41. The
separation process is a well
known process with the heavy oil industry. The gas separator reactor 33 and
the water-oil separator
reactor 35 are commercial available units. Any additional configuration to
enhance the gas-water-oil
separation can be used as well. The produce oil 41 is further treated in a
commercially available process
area BLOCK 1 commonly used with the insitue thermal oil recovery industry,
like SAGD or CSS. Solvents
can be added to the produced bitumen 41 to remove the water remains and other
contaminates. BLOCK
A includes commercial available water treatment facility, like evaporators, to
generate boiler feed water
quality water 40. The water feed to the water treatment plant in BLOCK 1 can
be from the water
remains in flow 41. Additional water can be directed to the water treatment
plant from water 43 that
was separated in vessel 35. The produced water used as feed to the boiler feed
water treatment plant is
de-oiled to remove oil traces that can impact the water treatment process in
BLOCK 1. Additional make-
up water can be added to the process in block 1 from any other water source,
like water wells. Usually
the make-up water do not include organic contaminates so it is easier to treat
them with evaporators
and other commercially available distillation units. (See Society of Petroleum
Engineers paper no
137633-MS Titled "Integrated Steam Generation Process and System for Enhanced
Oil Recovery"
presented by M. Betzer at the Canadian Unconventional Resources and
International Petroleum
Conference, 19-21 October 2010, Calgary, Alberta, Canada.) The produced water
flow 7, possibly with
solids contaminates and oil remains are mix with superheated steam 6. Due to
the contaminated within
the produce water feed 7 a rotating internal 2 is used to enhance the mixture
and remove build-ups
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within enclosure 1. Due to the driving steam 6 high temperatures (compared to
the saturated steam
temperature at the system pressure), liquid water from Flow 7 is converted to
steam. The amount of
water converted is a function of the ratio of the driving steam 6 and the
liquid water 7. If disposal wells
are available, it is possible to convert only portion of the water into steam
and disposed the remaining
water with the contaminated solids 12 into a disposal well 13. Heat can be
recovered from the disposal
liquid flow 12 through heat exchanger (not shown). The produced steam 20 is
separated from the
disposal flow 12 or 15 in a separation enclosure 10. If disposal wells for
disposing fluids are not available,
or ZLD facility is preferred, most of the water 7 can be converted to steam
generating solids or stable
slurry 15 for landfill disposal 16 or further treatment. The produced steam
flow 20 is used for injection
for thermal oil recovery through an injection well. Portion 21 of the produced
steam 20 is used to
generate the driving superheated steams 6. The clean BFW (Boiler Feed Water)
28 is used for generating
steam through commercial boiler or OTSG that include heat exchanger 26 to
generate High Pressure
steam 24. Any type of commercial available boiler and a steam separation
vessel can be used. The
produced HP steam 24 is used to recycle steam 21 to heater 27 to generate
superheated dry steam
stream 6 to drive the steam generation process at 1. The pumping and
circulating of the produced steam
21 is done through steam ejector 23 that use the pressure of the HP steam as
the energy source to
compress and circulate portion 21 of the produced steam 20 through the heat
exchanger 27. As
described the produced steam 21 can be further treated in a separate unit to
remove contaminates
from the produced steam flow, like silica, that can affect the super heater
heat exchanger 27
performance and create deposits. There are few technologies that can be used.
One option is to use a
liquid scrubber with saturated liquid water, possibly with chemicals, to
remove contaminates that can
affect the performance of the non-direct heat exchanger 27, or in some cases
the steam lines and the
injection well 31. Other technological solution to remove the undesired
contaminates from the steam
gas flow can be used as well. The feed water 40 is a treated water with low
level of contaminates as
required by ASME specifications for boiler feed water. There is a lot of
knowledge and commercial
available packages to generate the BFW 40 used for generated the high pressure
steam 24. In the
current sketch the boiler integrate the steam generation section 26 and the re-
heater section 27 for
generating super-heated driving steam 6 from the produced steam 21 and the
high pressure driving
steam 24 for operate ejector and as a driving steam. It is possible to
separate the production of the high
pressure steam 24 from the superheated steam into two separate units while the
steam 24 is generated
through package boiler, OTSG or any other type of commercially available
boiler, with any type of
carbon or hydrocarbon fuel. The produced steam 21 is heated to generate
superheated drive steam with
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any commercially available heat exchanger design. The heater can be integrated
into the boiler or a
separate unit with any available hearer design.
[54] FIGURE 7 is a schematic view of an integrated facility of the present
invention with a
commercially available steam generation facility and FOR for heavy oil
production. The steam for FOR is
generated using a lime softener based water treatment plant and OTSG steam
generation facility. This
type of configuration is most common in FOR facilities in Alberta. It recovers
bitumen from deep oil sand
formations using SAGD, CSS etc. Produced emulsion 3 from the production well
54, is separated inside
the separator facility to bitumen 4 and water 5. There are many methods from
separating the bitumen
from the water. The most common one uses gravity. Light hydrocarbons can be
added to the product to
improve the separation process. The water, with some oil remnants, flows to a
produced water de-oiling
facility 6. In this facility, de-oiling polymers are added. Waste water, with
oil and solids, is rejected from
the de-oiling facility 6. In a traditional system, the waste water would be
recycled or disposed of in deep
injection wells. The de-oiled water 10 is injected into a warm or hot lime
softener 12, where lime,
magnesium oxide and other softening chemicals are added 8. The softener
generates sludge 13. In a
standard facility, the sludge is disposed of in a landfill. The sludge is semi-
wet, and hard to stabilize. The
softened water 14 flows to a filter 15 where filter waste is generated 16. The
waste is sent to an ion-
exchange package 19, where regeneration chemicals 18 are continually used and
rejected with carry-on
water as waste 20. In a standard system, the treated water 21 flows to an OTSG
where approximately
80% quality steam is generated 27. The OTSG typically uses natural gas 25 and
air 26 to generate steam.
The flue gas is released to the atmosphere through a stack 24. Its saturated
steam pressure is around
100bar and the temperature is slightly greater than 300C. In a standard SAGD
system the steam is
separated in a separator, to generate 100% steam 29 for FOR and blow-down
water. The blow down
water can be used as a heat source and also to generate low pressure steam.
The steam, 29 is delivered
to pads, where it is processed and injected into the ground through an
injection well 53. In the current
method, additional dry superheated steam flow is produced to drive the SD-DCSG
in BLOCK 1 to
generate additional injection steam from the waste water stream. The
production well 54, located in
the FOR field facilities BLOCK 4, produces an emulsion of water and bitumen 3.
In some FOR facilities,
injection and production occur in the same well, where the steam can be 80%
quality steam 27. The
steam is then injected into the well with the water. This is typical of the
CSS pads where wells 53 and 54
are basically the same well. The reject streams include the blow down water
from OTSG 23, as well as
the oily waste water, solids and polymer remnants from the produced water de-
oiling unit. This also
includes sludge 13 from the lime softener, filtrate waste 16 from the filters
and regeneration waste from
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the Ion-Exchange system 20. The reject streams are collected 33 and injected
directly 33A into Steam
Drive Direct Contact Steam Generation 30 in BLOCK 1. The SD-DCSG can be
vertical, stationary,
horizontal or rotating. Dry solids 35 are discharged from the SD-DCSG, after
most of the liquid water is
converted to steam. The SD-DCSG generated steam 31 temperatures can vary
between 120C and 300C.
The pressure can vary between lbar and 50 bar. The produced steam 32 can be
injected directly 45A
into the injection well 53, possibly after additional solids and contamination
removal in BLOCK 32.
Another option is to wash the generated steam in wet scrubber 50 in BLOCK 2.
BLOCK 2 is optional and
can be bypassed by flows 33A and 45A. The produced steam from the SD-DCSG 31
is injected into a
scrubber vessel 50 where the steam gas is washed with saturated water 48 that
was condensed from
the produced gas 31 or from additional liquid water supplied to the wet
scrubber vessel 50 to remove
the solid remnants and possibly chemical contaminates. Solid rich water 51 is
continually removed from
the bottom of vessel 50. It is recycled back to the SD-DCSG, where the solids
are removed in dry or semi-
dry form 35. The liquid water is converted back to steam 31. The saturated
wash water in vessel 50 is
generated by removing heat through non-direct heat exchange with the feed
water 33. A portion of the
steam condenses to generate washing liquid water at vessel 50. The liquid
water continually recycled to
enhance the washing and the wet scrubbing. The SD-DCSG is driven by
superheated steam generated by
the steam generator 23 or in a separate boiler or in a separate heat exchanger
within the boiler (re-
heater type heat is exchanged to heat steam to produce a superheated steam).
There are many varieties
of commercially available options to generate the dry steam needed to drive
the process in the SD-
DCSG. The generated clean steam 45 is injected into an underground formation
for EOR.
[55] FIGURE 8 is a schematic of the invention with an open mine oilsand
extraction facility, where
the hot process water for the ore preparation is generated from condensing the
steam produced from
the fine tailings using a SD-DCSG. A typical mine and extraction facility is
briefly described in BLOCK 5.
The tailing water 27 from the oilsand mine facility is disposed of in a
tailing pond. The tailing ponds are
built in such a way that the sand tailings are used to build the containment
areas for the fine tailings.
The tailing sources come from Extraction Process. They include the cyclone
underflow tailings 13, mainly
coarse tailings, and the fine tailings from the thickener 18, where
flocculants are added to enhance the
solid settling and recycling of warm water. Another source of fine tailings is
the Froth Treatment
Tailings, where the tailings are discarded using the solvent recovery process-
characterized by high fines
content, relatively high asphaltene content, and residual solvent. (See "Past,
Present and Future Tailings,
Tailing Experience at Albian Sands Energy" a presentation by Jonathan Matthews
from Shell Canada
Energy on December 8, 2008 at the International Oil Sands Tailings Conference
in Edmonton, Alberta). A
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sand dyke 55 contains a tailing pond. The sand separates from the tailings and
generates a sand beach
56. Fine tailings 57 are put above the sand beach at the middle-low section of
the tailing pond. Some
fine tailings are trapped in the sand beach 56. On top of the fine tailing is
the recycled water layer 58.
The tailing concentration increases with depth. Close to the bottom of the
tailing layer are the MFT
(Mature Fine Tailings). (See "The Chemistry of Oil Sands Tailings: Production
to Treatment" presentation
by R.J. Mikula, V.A. Munoz, O.E. Omotoso, and K.L. Kasperski of CanmetENERGY,
Devon, Alberta, Natural
Resources Canada on December 8, 2008 at the International Oil Sands Tailings
Conference in Edmonton,
Alberta). The recycled water 41 is pumped from a location close to the surface
of. the tailing pond
(typically from a floating barge). The fine tailings that are used for
generating steam and solid waste in
this invention are the MFT. They are pumped from the deep areas of the fine
tailings 43. MFT 43 is
pumped from the lower section of the tailing pond and is then directed to the
SD-DCSG in BLOCK 1 and
in BLOCK 3. The SD-DCSG that includes BLOCKS 1-4 is described in Figure 5B.
However, any available SD-
DCSG that can generate gas and solids from the MFT can be used as well. Due to
the heat from the
superheated steam and pressure inside the SD-DCSG, the MFT turns into gas and
solids as the water is
converted to steam. The solids are recovered in a dry form or in a semi-dry,
semi-solid slurry form. The
semi-dry slurry form is stable enough to be sent back into the oilsand mine
without the need for further
drying to support traffic. The produced steam needed for extraction and froth
treatment, is generated
by a standard steam generation facility 61 used to generate the driving steam
for the DCSG in BLOCK 1
or from the steam produced from the SD-DCSG 62. The generated saturated steam
47 is mixed with the
process water 41 in mixing enclosure 45 to generate the hot water 52 used in
the extraction process in
BLOCK 5. By continually consuming the fine tailing water 43, the oil sand mine
facility can use a much
smaller tailing pond as a means of separating the recycled water from the fine
tailings. This solution will
allow for the creation of a sustainable, fully recyclable water solution for
the open mine oilsand
facilities.
[56] FIGURE 9 is a schematic view of the invention with an open mine oilsand
extraction facility
and a prior art commercially available pressurized fluid bed boiler that uses
combustion coal for
power supply. Examples of pressurized boilers are the Pressurized Internally
Circulating Fluidized-
bed Boiler (PICFB) developed and tested by Ebara, and the Pressurized-Fluid -
Bed-Combustion-
Boiler (PFBC) developed by Babcock-Hitachi. Any other pressurized combustion
boiler that can
combust petcoke or coal can be used as well. BLOCK 1 is a prior art
Pressurized Boiler. Air 64 is
compressed 57 and supplied to the bottom of the fluid bed combustor to support
the combustion.
Fuel 60, like petcoke, is crushed and grinded, possibly with lime stone 61 and
water 62, to generate
CA 02748477 2011-08-02
pumpable slurry 59. Water 62 is recycled water with high level of contaminates
38, as discharged
from the SD-DCSG 28. Some portion or stream 38A can be injected above the
combustion area to
directly recover heat from the combustion gas to generate steam. The boiler
includes an internal
heat exchanger 63 to generate high pressure steam 51 to drive the SD-DCSG. The
steam 51 is
generated from steam boiler drum 52 with boiler water circulation pump 58. The
boiler heat
exchanger 63 recovers energy from the combustion. BFW 37 is fed to the boiler
to generate steam
51. The steam can be heated again in a boiler heat exchanger (not shown) to
generate a
superheated steam stream. The steam used to drive the SD-DCSG 28. The boiler
generates
pressurized combustion gas and steam mixture 1 from the SD-DCSG discharged
water 24 at a
pressure of 103kpa and up to 1.SMpa and temperatures of 2000-9000. The
discharge flow is treated
in BLOCK 3 to generate a steam and combustion gas mixture for EOR. The mixture
8 is injected into
an underground formation through an injection well 7. There is no need to
remove solids from the
combustion gas 1 because this gas is fed to the DCSG in Block 3 that works as
a wet scrubber and
remove solids and possibly contaminated gas like SOx and NOx while creating a
steam and
combustion gas mixture. Solids from the fluid bed of the PFBC 55 can be
recovered to maintain the
fluid bed solids level. (This is a common practice in FBC (Fluid Bed
Combustion) and PFBC). The fluid
bed solids can be mixed with the DCSG solids from BLOCK 3 (not shown). The
pressurized
combustion gases leaving AREA#1 are mixed with the concentrate effluent from
SD-DCSG 28 and
possibly with other low quality waste water and slurry sources, like HLS/WLS
sludge produced by
SAGD/CSS water treatment plant (not shown). Block 2 includes a commercially
available FOR facility,
like SAGD, where the water and bitumen emulsion is treated to generate BFW
water quality and low
quality water that is fed into the SD-DCSG. There will be two types of
injection wells - for the
injection of pure steam from the SD-DCSG 6 and for the injection of a mixture
of steam and
combustion gases, mainly CO2 7. It is possible to combine the two types of FOR
fluids in one
production facility where the aging injection wells will be converted from
pure steam to a steam and
combustion gas mixture to pressurize the underground formation and increase
the bitumen
recovery due to the CO2 dissolved that increases the bitumen fluidity.
[57] FIGURE 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG.
Fuel 2 is
mixed with air 55 and injected into a Pressurized Fluidized-Bed Boiler 51. The
fuel 2 can be generated
from the water-bitumen separation process and includes reject bitumen slurry,
possibly with chemicals
that were used during the separation process and sand and clay remains.
Additional low quality carbon
fuel can be added to the slurry. This carbon or hydrocarbon fuel can include
coal, petcoke, asphaltin or
CA 02748477 2011-08-02
any other available fuel. Lime stone can be added to the fuel 2 or to the
water 52 to remove acid gases
like SOx. The Fluidized-Bed boiler is modified with water injection 52 to
convert it to a DCSG. It includes
reduced capacity internal heat exchangers to recover less combustion heat. The
reduction in the heat
exchanger required capacity is because more combustion energy will be consumed
due to the direct
heat exchange with the water within the fuel slurry 2 and the additional
injected solid rich water 52
leaving less available heat to generate high pressure steam through the boiler
heat exchangers 56. The
boiler produces high-pressure steam 59 from distilled, de-mineralized feed
water 37. The produced
steam 59, or part of it 31, can be re-heated in re-heater 56 to generate super
heated seam 32 to operate
the SD-DCSG in BLOCK 3. There are several pressurized boiler designs for BLOCK
1 that can be modified
with direct water injections. One example of such a design is the EBARA Corp.
PICFB (see paper No.
FBC99-0031 Status of Pressurized Internally Circulating Fluidized-Bed Gasifier
(PICFG) development
Project dated May-16-19, 1999 and US RE37,300 E issued to Nagato et al on July
31, 2001). Any other
commercially available Pressurized Fluidized Bed Combustion (PFBC) can be used
as well. Another
modification to the fluid bed boiler can be reducing the boiler combustion
pressure down to 102kpa.
This will reduce the plant TIC (Total Installed Cost) and the pumps and
compressors' energy
consumption. The superheated steam 32 is supplied to BLOCK 3 where it is used
by the SD-DCSG 28 for
generating additional steam from low quality water. BLOCK 2 includes a water
treatment facility as
previously described. The steam and combustion gas mixture stream 1 is
supplied to BLOCK 2 where the
water and heat can be used for generating clean BFW by evaporation /
distillation facility. The pressure
energy in flow 1 can be used to separate CO2 from the NCG using commercially
available membrane
technologies. The combustion oxidizer, like air, 55 is injected at the bottom
of the boiler to maintain the
fluidized bed. High pressure 100% quality steam 59 is generated from distilled
water 37 through heat
exchange inside the boiler 51. The generated steam 59 can be further heated in
heat exchanger 56 to
generate super-heated steam 32 that is used in BLOCK 3 as the driving steam
for the SD-DCSG 28. The
steam generated in BLOCK 3 is injected, through an injection well 16, into an
underground formation for
EOR. Hydrocarbons and water 13 are produced from the production well 15. The
mixture is separated in
a commercially available separation facility in BLOCK 2.
[58] FIGURE 11 is a schematic diagram of the present invention which includes
a steam
generation facility, SD-DCSG, a fired DCSG and MED water treatment plant.
BLOCK 1 is a standard,
commercially available steam generation facility that includes an atmospheric
steam boiler or OTSG 7.
Fuel 1 and air 2 are combusted under atmospheric pressure conditions. The
discharged heat is used to
generate steam 5 from de-mineralized distilled water 29. The combustion gas is
discharged through
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stack 3. The generated steam is supplied to SD-DCSG 11 in BLOCK 4 that
generates additional steam
from the concentrated brine 38 discharged from the MED in BLOCK 2. The
generated steam 8 is injected
into an underground formation 6. The liquid discharge 14 from SD-DCSG 11 is
injected into an internally
fired DCSG 15 in BLOCK 3. Carbon fuel 41, like petcoke or coal slurry, is
mixed with oxygen-rich gas 42
and combusted in a DCSG 15. Discharged liquids from the SD-DCSG 11 are mixed
with the pressurized
combustion gas to generate a stream of steam-rich gas and solids 13. To reduce
the amount of 502,
limestone can be added to the brine water 14 or to the fuel 41 injected into
the DCSG, to react with the
SO2. The solids are separated in separator 16. The separated solids 17 are
discharged in a dry form from
the solids separator 16 for disposal. The steam and combustion gas 12 flows to
heat exchanger 25 and
condenser 28. The steam in gas flow 12 is condensed to generate condensate 24.
The condensate is
treated (not shown) to remove contaminants and generate BFW that is added to
the distillate BFW 29
then supplied to the steam generation facility. The NCG (Non-Condensation Gas)
40 is released to the
atmosphere or used for further recovery, like CO2 extraction. The heat
recovered in heat exchanger 28
is used to generate steam to operate the MED 30 (a commercially available
package). The water 1 fed to
the MED is de-oiled produced water, possibly with make-up underground brackish
water. The Multi
Effect Distillation takes place in a series of vessels (effects) 31 and uses
the principles of condensation
and evaporation at a reduced pressure. The heat is supplied to the first
effect 31 in the form of steam
26. The steam 26 is injected into the first effect 31 at a pressure of 0.2bar
to 12 bar. The steam
condenses while feed water 32 is heated. The condensation 34 is collected and
used for boiler feed
water 37. Each effect consists of a vessel 31, a heat exchanger, and flow
connections, 35. There are
several commercial designs available for the heat exchanger area: horizontal
tubes with a falling brine
film, vertical tubes with a rising liquid, a falling film, or plates with a
falling film. The feed water 32 is
distributed on the surfaces of the heat exchanger and the evaporator. The
steam produced in each
effect condenses on the colder heat transfer surface of the next effect. The
last effect 39 consists of the
final condenser, which is continually cooled by the feed water, thus
preheating the feed water 1. To
improve the condensing recovery, the feed water can be cooled by air coolers
before being introduced
into the MED (not shown). The feed water may come from de-oiled produced
water, brackish water,
water wells or from any other locally available water source. The brine
concentrate 2 is recycled back, to
the SD-DCSG in BLOCK 4.
[591 FIGURE 11A is a view of the present invention that includes a steam
generation facility,
SD-DCSG and MED water treatment plant. BLOCK 1 is a standard, commercially
available steam
generation facility for generating super heated driving steam 5. The driving
steam 5 is fed to SD-DCSG in
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BLOCK 3. Discharged brine from the commercial MED facility in BLOCK 2 is also
injected to the SD-DCSG
15 and converted to steam and solid particles 13. The solids 17 are removed
for disposal. A portion of
the generated steam 12 is used to operate the MED through heat exchanger /
condenser 28. The
condensate 24, after further treatment (not shown), is used as BFW. The MED
produces distilled BFW 29
that is used to produce the driving steam at the boiler 7. The steam 8 is
injected through injection well 6
for EOR.
[60] FIGURE 11B is a schematic diagram of the present invention that includes
a steam drive
DCSG with a direct heated MSF (Multi Stage Flash) water treatment plant and a
steam boiler for
generating steam for EOR. Block 4 includes a commercially available steam
generation facility. Fuel 2 is
mixed with oxidized gas 1 and injected into the steam boiler (a commercially
available atmospheric
pressure boiler). If a solid-fuel boiler is used, the boiler might include a
solid waste discharge. The boiler
produces high-pressure steam 5 from distilled BFW 39. The steam is injected
into the underground
formation through injection well 6 for EOR. Portion of the steam can be used
to operate the DCSG. The
boiler combustion gas may be cleaned and discharged from stack 3. If natural
gas is used as the fuel 2,
there is currently no mandatory requirement in Alberta for further treatment
of the discharged flue gas
or for removal of CO2. Steam 9 injected into a pressurized DCSG 15 at an
elevated pressure. The DCSG
design can be a horizontal sloped rotating reactor, however any other reactor
that can generate a
stream of stean and solids can also be used. Solids - rich water 14 that
includes the brine from the MSF,
is injected into the direct contact steam generator 15 where the water
evaporates into steam and the
solids are carried on with gas flow 13. The amount of water 14 is controlled
to verify that all the water is
converted to steam and that the remaining solids are in a dry form. The solids
- rich gas flow 13 flows to
a dry solids separator 16. The dry solids separator is a commercially
available package and it can be used
in a variety of gas-solid separation designs. The removed solids 17 are taken
to a land-fill for disposal.
The steam flows to tower 25. The tower reacts as a direct contact heat
exchanger. Typically in MSF
processes, the feed water is heated in a vessel called the brine heater. This
is generally done by indirect
heat exchange by condensing steam on tubes that carry the feed water which
passes through the vessel.
The heated water then flows to the first stage. In the method described in
Fig. 11B, the feed water of
the MSF 45 is heated by direct contact heat exchange 25 (and not through an
indirect heat exchanger).
The feed water is injected into the up-flowing steam flow 12. The steam
condenses because of heat
exchange with the feed water 45. Non-direct heat exchanger / condensed can be
used as well to heat
brine flow 45 with steam flow 12 while condensing the steam flow 12 to liquid
water. In the MSF at
Block 30, the heated feed water 46 flows to the first stage 31 with a slightly
lower pressure, causing it to
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boil and flash into steam. The amount of flashing is a function of the
pressure and the feed water
temperature, which is higher than the saturate water temperature. The flashing
will reduce the
temperature to the saturate boiling temperature. The steam resulting from the
flashing water is
condensed on heat exchanger 32, where it is cooled by the feed water. The
condensate water 33 is
collected and used (after some treatment) 38 as BFW 39 in the standard,
commercially available, steam
generation facility 4. The number of stages can be up to 25. A commercial MSF
typically operates at a
temperature of 90-11OC. High temperatures increase efficiency but may
accelerate scale formation and
corrosion in the MSF. Efficiency also depends on a low condensing temperature
at the last stage. The
feed water for the MSF 9 can be treated by adding inhibitors to reduce the
scaling and corrosion 38.
Those chemicals are available commercially and the pretreatment package is
typically supplied with the
MSF. The feed water is recovered from the produced water in separation unit 10
that separates the
produced bitumen 8, possibly with diluent that improves separation from the
water and the viscosity of
the heavy bitumen. The de-oiled water 9 is supplied to the MSF as feed water.
There are several
commercially available separation units. In my applications, the separation
can be simplified as
discharged "oily contaminate water" 18 is allowed in the process. Make-up
water 29, like water from
water wells or from any other water source, is continually added to the
system. Any type of vacuum
pump or ejector can be used to remove gas 36 and generate the low pressure
required in the MSF
design.
[61] FIGURE 12 is an illustration of the use of a partial combustion gasifier
with the present
invention for the production of syngas for use in steam generation, a SD-DCSG
and a DCSG combined
with a water distillation facility for ZLD. The system contains few a
commercially available blocks, each
of which includes a commercially available facility:
BLOCK 1 includes the gasifier that produces syngas.
BLOCK 2 includes a commercially available steam generation boiler that is
capable of combusting
syngas.
BLOCK 3 includes a commercially available thermal water distillation plant.
BLOCK 7 includes syngas treatment plant where part of the syngas can be used
for hydrogen
production etc.
BLOCK 5 includes a water-oil separation facility with the option of oily water
discharge for recycling
into the SD-DCSG.
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BLOCK 4 includes SD-DCSG which generates the injection steam.
BLOCK 6 includes DCSG.
Carbon fuel 5 is injected with oxygen rich 6 gas to a pressurized gasifier 7.
The gasifier shown is a typical
Texaco (GE) design that includes a quenching water bath at the bottom. Any
other pressurized partial
combustion gasifier design can also be used. The gasifier can include a heat
exchanger, located at the
top of the gasifier (near the combustion section), to recover part of the
partial combustion energy to
generate high pressure steam. At the bottom of the gasifier, there is a
quenching bath with liquid water
to collect solids. Make-up water 13 is then injected to maintain the liquid
bath water level. The
quenching water 15, which includes the solids generated by the gasifier, is
injected into a DCSG 15
where it is mixed with the produced hot syngas discharged from the gasifier
12. The DCSG also
consumes the liquid water discharge 52 from the SD-DCSG 50. In the DCSG, the
water is evaporated into
pressurized steam and solids (which were carried with the water and the syngas
into the DCSG). The
DCSG generates a stream of gas and solids 16. The solids 19 are removed from
the gas flow by a
separator 17 for disposal. The solids lean gas flow 18 (after most of the
solids have been removed from
the gas) is injected into a pressurized wet scrubber 20 that removes the solid
remains and can generate
saturated steam from the heat in gas flow 18 as well. Solids rich water 25 is
continually rejected from
the bottom of the scrubber and recycled back to the DCSG 15. Heat 27 is
recovered from the saturated
water and syngas mixture 21 while condensing steam 21 to liquid water 35 and
water lean syngas 36.
The condensed water 35 can be used as BFW after further treatment to remove
contaminations (not
shown). The heat 27 is used to operate a thermal distillation facility in
BLOCK 3. There are several
commercially available facilities for this, like MSF (Multi Stage Flashing) or
MED (Multi Effect
Distillation). The distillation facility uses de-oiled produced water 30,
possibly with make-up brackish
water 31 and heat 27, to generate a stream of de-mineralized BFW 29 for steam
generation and a
stream of brine water 28, with a high concentration of minerals. The generated
brine 28 is recycled back
to the SD-DCSG 50 in BLOCK 4. The syngas can be treated in commercially
available facilities BLOCK 7 to
remove H2S using amine or to recover hydrogen. The treated syngas 37, together
with oxidizer 38, is
used as a fuel source in the commercially available steam generation facility
BLOCK 2. The super heated
steam 40 is generated in steam boiler 39 from the BFW 29. The steam from the
boiler 40, possibly
together with the steam generated by the gasifier 10, is injected into the SD-
DCSG 50 in BLOCK 4 where
additional steam is generated from low quality water 53. The generated steam
51 is injected into an
underground formation for EOR. The produced bitumen and water recovered from
production well 44
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are separated in the water-oil separation facility BLOCK 5 to produce bitumen
33 and de-oiled water 30.
Oily water 34 can be rejected and consumed in the SD-DCSG 50. By allowing
continuous rejection of oily
water, the chemical consumption can be reduced and the efficiency of the oil
separation unit can be
improved.
[62] FIGURE 13 is a schematic of the present invention for the generation of
hot water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Block 1A includes a Prior Art
commercial open mine oilsands plant. The plant consists of mining oilsands ore
and mixing it with hot
process water, typically in a temperature range of 70C-90C, separating the
bitumen from the water,
sand and fines. The cold process water 8 includes recycled process water
together with fresh make-up
water that is supplied from local sources (like the Athabasca River in the
Wood Buffalo area). Another
bi-product from the open mine oilsands plant is Fine Tailing (FT) 5 which,
after a time, is transferred to a
stable Mature Fine Tailings (MFT). Energy 1 is being injected into reactor 3.
The energy is in the form of
steam gas. The hot, super heated ("dry") steam gas is mixed in enclosure 3
with a flow of FT 5 from
Block IA. Most of the liquid water in the FT is converted to steam. The
remaining solids 4 are removed
in a solid stable form to use as a back-fill material and support traffic. The
produced steam 21 is at a
lower temperature than steam 1 and contains additional water from the FT that
was converted to
steam. Steam 1 can be generated by heating the produced steam 21 as described
in Fig. 3, 3A or 3B (not
shown). The produce steam 21 is mixed with cold process water 8 from Block 1A
in a direct contact
heat exchanger 7. The produced steam directly heat and condense into the
liquid water 8 to generate
hot process water 9 that is supplied back to operate the Open Mine Oilsands
plant 1A. The amount of
Non Condensable Gases (NCG) 2 is minimal. Some NCG can be generated from the
organics
contaminates in the FT S. The enclosure 3 system pressure can vary from 103kpa
to 50000kpa and the
temperature at the discharge point 21 can vary from 100C to 400C.
[63] FIGURE 13A is a schematic view for a process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Figure 13A is substantially similar
to figure 13 with the difference that non-direct heat exchange is used between
the drive steam 1 and
the FT or MFT 5. Block 1A includes a Prior Art commercial open mine oilsands
plant. The plant consists
of mining oilsands ore and mixing it with hot process water, typically in a
temperature range of 70C-
90C, separating the bitumen from the water, sand and fines. The cold process
water 8 includes recycled
process water together with fresh make-up water that is supplied from local
sources (like the Athabasca
River in the Wood Buffalo area). Another bi-product from the open mine
oilsands plant is Fine Tailing
(FT) 5 which, after a time, is transferred to a stable Mature Fine Tailings
(MFT). Energy 1 is being
CA 02748477 2011-08-02
injected into reactor 3. The energy is in the form of steam gas injected
around enclosure 3 where the
heat is transferred into the reactor and to the MFT through the enclosure
wall. The driving hot steam
gas is condensed and recovered as a liquid condensate 1A. The driving steam 1
heat energy is
transferred to the enclosure and used to evaporate the FT 5. Most of the
liquid water in the FT is
converted to steam. The remaining solids 4 are removed in a solid / slurry
stable form to use as a back-
fill material and support traffic. Steam 1 is generated by a standard boiler
heating the condensate 1A in
a closed cycle, allowing the use of high quality clean ASME BFW (not shown).
The produce steam 21 is
mixed with cold process water 8 from Block 1A in a direct contact heat
exchanger 7. The produced
steam directly heat and condense into the liquid water 8 to generate hot
process water 9 that is
supplied back to operate the Open Mine Oilsands plant 1A. The amount of Non
Condensable Gases
(NCG) 2 is minimal. Some NCG can be generated from the organics contaminates
in the FT 5. The
enclosure 3 system pressure can vary from 103kpa to 50000kpa and the
temperature at the discharge
point 21 can vary from 100C to 400C.
[64] FIGURE 13B is a schematic view for a process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Figure 13B is substantially similar
to figure 13A with rotating internals to enhance the heat transfer between the
evaporating MFT and
the heat source which is the steam 1 in the enclosure 3. The rotating
internals also mobilized the high
concentration slurry and solids to the solid discharge 4, where stable
material that can support traffic is
discharged from the system. The produce steam 6 is further cleaned to remove
solids in commercially
available solids separation unit 20 like cyclone, electrostatic filter or any
other commercial available
system. The generated steam 21 mixed with cold process water 8 supplied from
an open mine
extraction plant in a direct contact heat exchanger 7. The produced steam
directly heat and condense
into the liquid water 8 to generate hot process water 9 that is supplied back
to operate the extraction
Open Mine Oilsands plant.
[65] FIGURE 14 is one illustration of the present invention for the generation
of pre-heated
water that can be used for steam generation or mining extraction facility. The
invention has full disposal
water recycling, so as to achieve zero liquid discharge. Energy 1, in the form
of super heated steam is
introduced to the Direct Contact Steam Generator reactor 3. Contaminated water
5, like FT or MFT, is
injected into reactor 3. There, most of the water is converted to steam,
leaving solids with a low
moisture content. There are several possibilities for the design of reactor 3.
The design can be a
horizontal rotating reactor, an up-flow reactor, or any other type of reactor
that can be used to
generate a stream of solids and gas. A stream of hot gas 6, possibly with
carried-on solids generated in
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reactor 3, flows into a commercially available solid-gas separator 20. Solids
4 can also be discharged
directly from the reactor 3, depending on the type of reactor used. The
separated solids 22 and 4 are
disposed of in a landfill. The solids lean steam flow 21, (rich with steam
from flow 5) condensed into
liquid water 10 in non-direct condenser 7. There are many commercially
available standard designed for
heat-exchanger / condenser that can be used at 7. The steam heat is used to
heat flow 8, like process
water flow, to generate hot water 9 that can be used in the extraction
process. Low volume of NCG 2
can be treated or combust as a heat source (not shown). The condensed liquid
water 10 can be used a
hot process water for the extraction process or any other usage. The steam in
flow 21 condenses by
non-direct contact with the recycled water 8. Solid remains that previously
passed through solid
separation unit 20 and were carried on with the gas flow 21, are washed with
the condensed water 10.
(661 FIGURE 15 is a schematic of the invention with an open mine oilsands
extraction
facility, where the steam source is a standard gasifier for generating steam
in non-direct hear exchange
and syngas that can be used for the production of hydrogen for upgrading the
produced crude in a
prior-art technologies or as a fuel source. The MFT recovery is done with the
steam produced by the
gasifier and not with the syngas. The partial combustion of fuel 56 and
oxidizer, like enriched air, takes
place inside the gasifier 54. The gasification heat is used to produce
superheated steam 55 from BFW
(Boiler Feed Water) 59. The produce syngas 60 is recovered and further
treated. This treatment can
include the removal of the H2S (like in an amine plant). It can also include
generating hydrogen for
crude oil upgrading or as a fuel source to replace natural gas usage (not
shown). The steam 55 flows to
a horizontal parallel flow DCSG 1. Concentrated MFT 2 is also injected into
the DCSG. The MFT is
converted to gas- mainly steam, and solids 6. The solids 8 are removed in a
solid gas separator 7. The
solid lean stream flows through heat exchanger 11, where it heats the process
water or any other
process flow 12, indirectly through a heat exchanger. Condensing hot water 13
is removed from the
bottom of 11 and used as hot process extraction water. In case NCG 17 is
generated, it can be further
treated or combust as a fuel source. The fine tailings 14 are pumped from the
tailing pond and can then
be separated into two flows through a specific separation process. Separation
15 is one option to
increase the amount of MFT removal. The process can use natural MFT both at
flows 2 and 16. This
separation can be based on a centrifuge or on a thickener (like a High
Compression Thickener or
Chemical Polymer Flocculent based thickener). This unit separates the fine
tailings into solid rich 16 and
solid lean 2 flows. The solid lean flow is fed into the DCSG 1 or recycled and
used the process water (not
shown). In the DCSG 1 dry solids are generated and removed from the gas-solid
separator. The solid rich
flow 16 is mixed with the dry solids 8 in a screw conveyor to generate a
stable material 27.
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[67] FIGURE 16 is a schematic of the invention with an open mine oilsands
extraction
facility, where the hot process water for the ore preparation is generated by
recovering the heat and
condensing the steam generated from the fine tailings without the use of a
tailing pond. A typical mine
and extraction facility is briefly described in block diagram 1 (See "Past,
Present and Future Tailings,
Tailing Experience at Albian Sands Energy" presentation by Jonathan Matthews
from Shell Canada
Energy on December 8, 2008 at the International Oil Sands Tailings Conference
in Edmonton, Alberta).
Mined Oil sand feed is transferred in trucks to an ore preparation facility,
where it is crushed in a semi-
mobile crusher 3. It is also mixed with hot water 57 in a rotary breaker 5.
Oversized particles are
rejected and removed to landfill. The ore mix goes through slurry
conditioning, where it is pumped
through a special pipeline 7. Chemicals and air are added to the ore slurry 8.
In the invention, the NCGs
(Non Condensed Gas) 58 that are released under pressure from tower 56 can be
added to the injected
air at 8 to generate aerated slurry flow. The conditioned aerated slurry flow
is fed into the bitumen
extraction facility, where it is injected into a Primary Separation Cell 9. To
improve the separation, the
slurry is recycled through floatation cells 10. Oversized particles are
removed through a screen 12 in the
bottom of the separation cell. From the flotation cells, the coarse and fine
tailings are separated in
separator 13. The fine tailings flow to thickener 18. To improve the
separation in the thickener,
flocculant is added 17. Recycled water 16 is recovered from the thickener and
fine tailings are removed
from the bottom of thickener 18. The froth is removed from the Primary
Separation Cell 9 to vessel 21.
In this vessel, steam 14 is injected to remove air and gas from the froth. The
recovered froth is
maintained in a Froth Storage Tank 23. The coarse tailings 15 and the fine
tailings 19 are removed and
sent to tailing processing area 60. The fine and coarse tailings can be
combined or removed and sent
separately (not shown) to the tailing process area 60. In unit 60, the sand
and other large solid particles
are removed and then put back into the mine, or stored in stock-piles. Liquid
flow is separated into 3
different flows, mostly differing in their solids concentration. A relatively
solids - free flow 62 is heated.
This flow is used as heated process water 57 in the ore preparation facility,
for generation of the
oilsands slurry 6. The fine tailings stream can be separated into two sub
streams. The most
concentrated fine tailings 51 are mixed with dry solids, generated by the
DCSG, to generate a solid and
stable substrate material that can be put back into the mine and used to
support traffic. The medium
concentrated fine tailing stream 61 flows to DCSG facility 50. Steam energy 47
is used in the DCSG to
convert the fine tailing 61 water into a dry or semi dry solid and gas stream.
The steam can be produced
in a standard high pressure steam boiler 40, in OTSG, or by a COGEN, using the
elevated temperature in
a gas turbine tail (not shown). The boiler consumes fuel gas 38 and air 39
while generating steam 14.
CA 02748477 2011-08-02
Portion 47 of the generated steam 14 can be injected to the DCSG 50. The
temperature of the DCSG
produced steam can vary from 100C to 400C as it includes the water from the
MFT. Steam 47 can be
also generated by heating a portion of the produces steam 52 as described in
figures 3, 3A and 3B. The
solids are separated from the gas stream in any commercially available
facility 45 which can include:
cyclone separators, centrifugal separators, mesh separators, electrostatic
separators or other
combination technologies. The solids lean steam 52 flows into tower 56. The
gas flows up into the
tower, possibly through a set of trays, while any solid carried-on remnants
are scrubbed from the up
flowing gas through direct contact with liquid water. The water vapor that was
generated from heating
the fine tailing 61 in the DCSG and the steam that provided the energy to
evaporated the FT is
condensed and is added to the down-flowing extraction water process 57. The
presence of small
amounts of remaining solids in the hot process water can be acceptable. That
is because the hot water
is mixed with the crushed oilsands 3 in the breaker during ore preparation.
The temperature of the
discharged hot water 57 is between 70C and 95C, typically in the 80C-90C
range. The hot water is
supplied to the ore preparation facility. The separated dry solids from the
DCSG are mixed with the
concentrated slurry flow from the tailing water separation facility 60. They
are used to generate a
stable solid waste that can be returned to the oilsands mine for back-fill and
support traffic. Any
commercially available mixing method can be used in the process: a rotating
mixer, a Z type mixer, a
screw mixer, an extruder or any other commercially available mixer. The slurry
51 can be pumped to
the mixing location, while the dry solids can be transported pneumatically to
the mixing location. The
described arrangement, where the fine tailings are separated into two streams
61 and 51, is intended
to maximize the potential of the process to recover MFT. It is meant to
maximize the conversion of fine
tailings into solid waste for each unit weight of the supplied fuel source.
The system can work in the
manner described for tailing pond water recovery. The tailing pond water is
condensed into hot water
generation 57, without the combination of the dry solids 53 and tailing slurry
51. The generated dry
solids 53 are a "water starving" dry material. As such, they are effective in
the process of drying MFT
(Mature Fine Tailing), to generate trafficable solid material without relying
on weather conditions to dry
excess water.
[681 FIGURE 17 is a schematic of the invention with an open mine oilsand
extraction facility,
where the hot process water for the ore preparation is generated from
condensing the steam produced
from the fine tailings. A typical mine and extraction facility is briefly
described in block diagram 1. The
tailing water from the oilsands mine facility 1 is disposed of in a tailing
pond. The tailing ponds are built
in such a way that the sand tailings are used to build the containment areas
for the fine tailings. The
CA 02748477 2011-08-02
tailing sources come from Extraction Process. They include the cyclone
underflow tailings 13, mainly
coarse tailings and the fine tailings from the thickener 18, where flocculants
are added to enhance the
solid settling and recycling of warm water. Another source of fine tailings is
the Froth Treatment
Tailings, where the tailings are discarded using the solvent recovery process-
characterized by high
fines content, relatively high asphaltene content, and residual solvent. (See
"Past, Present and Future
Tailings, Tailing Experience at Albian Sands Energy" a presentation by
Jonathan Matthews from Shell
Canada Energy on December 8, 2008 at the International Oil Sands Tailings
Conference in Edmonton,
Alberta). A sand dyke 55 contains a tailing pond. The sand separates from the
tailings and generates a
sand beach 56. Fine tailings 57 are put above the sand beach at the middle-low
section of the tailing
pond. Some fine tailings are trapped in the sand beach 56. On top of the fine
tailing is the recycled
water layer 58. The tailing concentration increases with depth. Close to the
bottom of the tailing layer
are the MFT (Mature Fine Tailings). (See "The Chemistry of Oil Sands Tailings:
Production to Treatment"
presentation by R.J. Mikula, V.A. Munoz, O.E. Omotoso, and K.L. Kasperski of
CanmetENERGY, Devon,
Alberta, Natural Resources Canada on December 8, 2008 at the International Oil
Sands Tailings
Conference in Edmonton, Alberta). The recycled water 41 is pumped from a
location close to the
surface of the tailing pond (typically from a floating barge). The fine
tailings that are used for generating
steam and solid waste in my invention are the MFT. They are pumped from the
deep areas of the fine
tailings 43. Steam 48 is injected into a DCSG. MFT 43 is pumped from the lower
section of the tailing
pond and is then directed to the DCSG 50. The DCSG described in this
particular example is a horizontal,
counter flow rotating DCSG. However, any available DCSG that can generate gas
and solids from the
MFT can be used as well. Due to the heat and pressure inside the DCSG, the MFT
turns into gas and
solids as the water is converted to steam. The solids are recovered in a dry
form or in a semi-dry, semi-
solid slurry form 51. The semi-dry slurry form is stable enough to be sent
back into the oilsands mine
without the need for further drying to support traffic. The produced steam 14,
that portion 48 can be
used to operate the DCSG is generated by a standard steam generation facility
36 from BFW 37, fuel gas
38 and air 39. The blow-down water 20 can be recycled into the process water
20. By continually
consuming the fine tailing water 43, the oil sand mine facility can use a much
smaller tailing pond as a
means of separating the recycled water from the fine tailings. This smaller
recyclable tailing pond is cost
effective, and it is the simplest way to do so as it does not involve any
moving parts (in contrast to the
centrifuge or to thickening facilities). This solution will allow for the
creation of a sustainable, fully
recyclable water solution for the open mine oilsands facilities. Steam 48 can
be generated by heating a
portion of the produces steam 47 as described in figures 3, 3A and 3B.
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[69] FIGURE 18 is a schematic of the invention with open mine oilsands
extraction facility,
where the hot process water for the ore preparation is generated from
condensing the steam
generated from the fine tailings and the driving steam. The tailing water from
the oilsands mine facility
43 (not shown) is disposed of in a tailing pond. Steam 4 is fed into a
horizontal parallel flow DCSG 1.
Concentrated MFT 2 is injected into the DCSG 1 as well. The MFT is converted
to steam, and solids. The
solids are removed in a solid gas separator 7 where the solid lean stream is
washed in tower 10 by
saturated water. In the tower, the solids are washed out and then removed. The
solid rich discharge
flow 13 can be recycled back to the DCSG or to the tailing pond. Heat is
recovered from saturated
steam 16 in heat exchanger / condenser 17. Steam is condensed to water 20. The
condensed water 20
can be used as hot process water and can be added to the flow 24. The
recovered heat is used for
heating the process water 35. The fine tailings 32 are pumped from the tailing
pond and separated into
two flows by a centrifugal process 31. This unit separates the fine tailings
into two components: solid
rich 30 and solid lean 33 flows. The centrifuge unit is commercially available
and was tested successfully
in two field pilots (See "The Past, Present and Future of Tailings at
Syncrude" presentation by Alan Fair
from Syncrude on December 7-10, 2008 at the International Oil Sands Tailings
Conference in Edmonton,
Alberta). Other processes, like thickening the MFT with chemical polymer
flocculent, can be used as
well instead of the centrifuge. The solid lean flow can contain less than 1%
solids. The solid rich flow is
thick slurry ("cake") that contains more than 60% solids. The solid lean flow
is directly used or is
recycled back to a settling basin (not shown) and eventually used as process
water 35. The solid
concentration is not dry enough to be disposed of efficiently and to support
traffic. This can be solved
by mixing it with the "water starving" material (virtually dry solids
generated by the DCSG). Mixing of
the dry solids and the thick slurry can be achieved through many commercially
available methods. In
this particular figure, the mixture is done by a screw conveyer 29 where the
slurry 30 and the dry
material 8 are added to the bottom of a screw conveyor, mixed by the screw,
and then the stable solids
are loaded on a truck 28 for disposal. The produced solid material 27 can be
backfilled into the oilsands
mine excavation site and then used to support traffic. It is also possible to
feed the thickened MFT
directly to the DCSG 1, eliminating the additional mixing process. In this
particular figure, there are two
options for supplying the fine tailing water to the DCSG: one is to supply the
solid rich thick slurry 30
from the centrifuge or thickening unit 31. The other is to provide the
"conventional" MFT, typically with
30% solids, pumped from the settlement pond. Feeding the MFT "as is" to the
DCSG eliminates the TIC,
operation, and maintenance costs for a centrifuge or thickening facility.
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[701 FIGURE 19 is an illustration of one embodiment of the present invention.
Fuel 2 is
mixed with oxidizing gas 1 and injected into the steam boiler 4. The boiler is
a commercially available
atmospheric pressure boiler. If a solid fuel boiler is used, the boiler might
include a solid waste
discharge. The boiler produces high-pressure steam 5 from distilled BFW 19.
The steam is injected into
the underground formation through injection well 6 for EOR. The boiler
combustion gas are possibly
cleaned and discharged from stack 32. If natural gas is used as the fuel 2,
there is currently no
mandatory requirement in Alberta to further treat the discharged flue gas or
remove CO2. Steam 9 is
injected into a pressurized, direct - contact steam generator (DCSG) 15 at an
elevated pressure. The
DCSG design can include a horizontal rotating reactor, a fluidized bed reactor
and an up-flow reactor or
any other reactor that can be used to generate a stream of gas and solids.
Solids - rich water 14 is
injected into the direct contact steam generator 15 where the water evaporates
to steam and the solids
are carried on with gas flow 13. The amount of water 14 is controlled to
verify that all the water is
converted to steam and that the remaining solids are in a dry form. The solid -
rich gas 13 flows to a dry
solids separator 16. The dry solids separator is a commercially available
package and it can be used in a
variety of gas-solid separation designs. The solids 17 are taken to a land-
fill. The solids lean flow 12
flows to the heat exchanger 30. The steam continually condenses because of
heat exchange. Heat 25 is
recovered from gas flow 12. The condensed water 36 can be used for steam
generation. The
condensation heat 25 can be used to supply the heat to operate the
distillation unit 11. The distillation
unit 11 produces distillation water 19. The brine water 26 is recycled back to
the direct contact steam
generator 15 where the liquid water is converted to steam and the dissolved
solids remain in a dry
form. The distillation unit 11 receives de-oiled produced water 39 that is
separated in a commercially
available separation facility 10 like that which is currently in use by the
industry. Additional make-up
water 34 is added. This water can be brackish water, from deep underground
formation, or from any
other water source that is locally available to the oil producers. The quality
of the make-up water 34 is
suitable for the distillation facility 11, where there are typically very low
levels of organics due to their
tendency to damage the evaporator's performance or carry on and damage the
boiler. Water that
contains organics is a by-product of the separation unit 10 and it will be
used in the DCSG 15. By
integrating the separation unit 10 and the DCSG 15, the organic contaminated
by-product water can be
used directly, without any additional treatment by the DCSG 15. This
simplifies the separation facility 10
that can reject contaminated water without environmental impact. It is sent to
the DCSG 15, where
most of the organics are converted to hydrocarbon gas phase or carbonic with
the hot steam gas flow.
The distilled water 19 produced by the distillation facility 11, possibly with
the condensed steam from
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flow 12, are sent to the commercially available, non-direct, steam generator
4. The produced steam 5 is
injected into an underground formation for EOR. The brine 26 is recycled back
14 to the DCSG and
solids dryer 15 as described before. The production well 7 produces a mixture
of tar, water and other
contaminants. The oil and the water are separated in commercially available
plants 10 into water 9 and
oil product 8.
[71] FIGURE 20 is an illustration of one embodiment of the present invention.
It is similar to
FIG. 19 with the following modifications described below: The solids lean flow
12 is mixed with
saturated water 21 in vessel 20. The heat carried in the steam gas 12 can
generate additional steam if
its temperature is higher than the saturated water 21 temperature. The solids
carried with the steam
gas are washed by saturated liquid water 23. The solids rich water 24 is
discharged from the bottom of
the vessel 20 and recycled back to the DCSG 15 where the liquid water is
converted to steam and the
solids are removed in a dry form for disposal. Saturated "wet" solids free
steam 22 flows to heat
exchanger / condenser 30. The condensed water 36 is used for steam generation.
The condensation
heat 25 is used to operate a water treatment plant 11 as described in FIG. 19
above. To minimize the
amount of steam 9 used to drive the DCSG 15, it is possible to recycled
portion of the produced
saturated steam 22 as described in Fig. 3, 3A and 3B. This option is shown in
dotted line. Portion of the
produced steam 22 is recycled to drive the process. This steam is compressed
42 to allow the recycle
flow and overcome the heater and the SD- DCSG pressure drop. The steam is
heated in a non-direct
heat exchanger 41. Any type of heat exchanger / heater can be used at 41. One
example is the use of a
typical re-heater 43 that is a typical part from a standard boiler design.
[72] FIGURE 21 is an illustration of a boiler, steam drive DCSG, solid removal
and Mechanical
Vapor Compression distillation facility for generating distilled water for
steam generation in the boiler
for EOR. Block 4 includes a steam generation unit. Fuel 2, possibly with water
in a slurry form, is mixed
with air 1 and injected into a steam boiler 4. The boiler may have waste
discharged from the bottom of
the combustion chamber. The boiler produces high-pressure steam 3 from treated
distillate feed water
5. The steam is injected into the underground formation through injection well
21 for EOR. Part of the
steam 7 is directed to drive a DCSG 9. Block 22 includes a steam drive DCSG 9.
Solids rich water, like
concentrate brine 8 from distillation facility, is injected to the DCSG 9
where the water is mixed with
super heated steam 7. The liquid water phase is converted to steam due to the
high temperature of the
driving steam 7. The DCSG can be a commercially available direct-contact
rotary dryer or any other type
of direct contact dryer capable of generating solid waste and steam from solid
- rich brine water 8. The
DCSG generates a stream of steam gas 10 with solid particles from the solid
rich water 8. The DCSG in
CA 02748477 2011-08-02
Block 22 can generate its own driving steam 7 by recycling and heating portion
of the saturated
produced steam 12 as described in Fig. 3, 3A and 3B (not shown). The amount of
water 8 is controlled
to verify that all the water is converted to steam and that the remaining
solids are in a dry form. The
solid - rich steam gas flow 10 is directed to Block 21 which separates the
solids. The solid separation is
in a dry solids separator 12. The dry solids separator is a commercially
available package and it can be
used in a variety of gas-solid separation designs. The solids lean flow 11 is
mixed with saturated water
22 in a direct contact wash vessel 15. The solids remains carried with the
steam are washed by
saturated liquid water 22. The solids rich water 14 is discharged from the
bottom of the vessel 22 and
recycled back to dryer 9 where the liquid water is converted to steam and the
solids are removed in a
dry form for disposal. If the dry solid removal efficiency at 12 is high, it
is possible to eliminate the use
of the saturate water liquid scrubber 15. The produced saturated steam 23 is
supplied to Block 20,
which is commercially available distillation unit produces distillation water
5. The brine water 8 is
recycled back to the direct contact steam generator / solids dryer 15 where
the liquid water is
converted to steam and the dissolved solids remain in dry form. Distillation
unit 19 is a Mechanical
Vapor Compression (MVC) distillation facility. It receives de-oiled produced
water 16 that has been
separated in a commercially available separation facility currently in use by
the industry with additional
make-up water (not shown). This water can be brackish, from deep underground
formations or from
any other water source that is locally available to the oil producers. The
quality of the make-up water is
suitable for the distillation facility 20, where there are typically very low
levels of organics due to their
tendency to damage the evaporator's performance or damage the boiler further
in the process. The
distilled water produced by distillation facility 19 is treated by the
distillate treatment unit 17, typically
supplied as part of the MVC distillation package. The treated distilled water
5 can be used in the boiler
to produce 100% quality steam for EOR. The brine 8 and possibly the scrubbing
water 14 are recycled
back to the DCSG/dryer 9 as previously described. The heat from flow 23 is
used to operate the
distillation unit in Block 20. The condensing steam from flow 23 recovered in
the form of liquid distilled
water 5. The high - pressure steam from the boiler in Block 4 is injected into
the injection well 21 for
FOR or for other uses (not shown). With the use of a low pressure system, the
thermal efficiency of the
system is lower than using a high pressurized system with pressurized DCSG
instead of a low pressure
dryer.
[73] The following are example for heat and material balance simulation:
CA 02748477 2011-08-02
[74] Example 1: The graph in figure 22 simulates the process as described in
Figure 2A.
The system pressure was constant at 25bar. The liquid water 7 was at
temperature of 25C with a
constant flow of 1000 kg/hour. The product 8 was saturated steam at 25bar. The
graph shows the
amount of drive steam 9 required to transfer the liquid water 7 into gas phase
as a function of the
temperature of the driving steam 9. When 300C driving steam is used, there is
a need in 12.9ton/hour of
steam 9 to gasify one ton/hour of liquid water 7. When 500C driving steam is
used, there is a need in
only 4.1ton/hour of steam 9 to gasify one ton/hour of liquid water 7. The
following are the result of the
simulation:
Drive Drive
Steam 9 Steam 9 Flow
Temperature(C ) (kg/hr)
600.00 3059.20
550.00 3502.50
500.00 4091.50
450.00 4914.46
400.00 6159.21
350.00 8290.00
300.00 12990.00
250.00 34950.00
CA 02748477 2011-08-02
[75] Example 2: The graph in Figure 23 simulates the process as described in
Figure 2A. The
driving steam 9 temperature was constant at 450C . The liquid water 7 was at
temperature of 25C and
constant flow of 1000kg/hour. The produced steam product 8 was saturated. The
graph shows the
amount of drive steam 9 required to transfer the liquid water 7 into gas phase
as a function of the
pressure of the driving steam 9. When the system pressure was 2 bar, a 3.87
ton/hour of driving steam
was needed to convert the water to saturated steam at temperature of 121C .
For 50 bar system
pressure, 5.14 ton/hour of driving steam was used to generate saturated steam
at 256C . The
simulation results summarized in the following table:
System Temperature of Driving steam
Pressure Saturated pressure
(bar) produced Steam (kg/hr)
100.00 311.82 5127.94
75.00 291.35 5161.78
50.00 264.74 5135.66
25.00 224.70 4914.46
20.00 213.11 4821.42
15.00 198.98 4696.41
10.00 180.53 4515.83
5.00 152.40 4218.44
3.00 134.03 4018.992
2.00 120.68 3870.57
1.00 100.00 3649.728
CA 02748477 2011-08-02
[76] Example 3: The graph in Figure 24 simulates the process as described in
Figure 2A
where the water feed includes solids and naphtha. As the pressure increases,
the saturated
temperature of the steam also increases from around 100C at lbar to around
312C 100bar. Thus the
amount of superheated steam input at 450C also increases from around 2300
kg/hr to 4055 kg/hr. The
graph in Figure 24 represents the superheated driving steam input 9 and the
total flow rate (including
hydrocarbons) of the produced gas 8.
Flow Number 7 9 12 8
r,C 25.00 450.00 120.61 120.61
P,atm 2.00 2.00 2.00 2.00
Vapor Fraction 0.00 1.00 0.00 1.00
Enthalpy, MJ -14885.08 -29133.36 -6692.49 -37325.62
Total Flow, kg/hr 1000.00 2311.54 414.73 2896.81
Water 600.00 2311.54 114.20 2797.34
Solids 300.00 0.00 300.00 4.14E-17
Naptha 100.00 0.00 0.53 99.47
CA 02748477 2011-08-02
[77] Example 4: The following table simulates the process as described in
Figure 3 for
insitue oilsands thermal extraction facility like SAGD for two different
pressures. The water feed is hot
produced water at 200C that includes solids and bitumen. The heat source Q'
for the simulation was
12KW.
For system pressure of 400psi the total Inflow of Water + solids + Bitumen of
flow 34 were 23.4 kg. 77%
of the steam 31 recycles as the driving steam 32 while 23% is discharged out
of system at 283C Steam +
hydrocarbons.
For system pressure of 600psi the total Inflow of Water + solids + Bitumen of
flow 34 were 22.5 kg. 80%
of the steam 31 recycles as the driving steam 32 while 20% is discharged out
of system at 283C Steam +
hydrocarbons.
Flow Number 34 35 31 32 36 33
T, C 200 243.42 243.42 243.43 486.73 243.43
Press., psig 400 400 400 400 400.00 400.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00
Enthalpy, kW -96.591 -5.06 -346.24 -266.80 -254.78 -79.69
Total Flow, kg/hr 23.4 1.17 96.89 74.66 74.66 22.30
Water, kg/hr 21.76 0.00 94.84 73.08 73.08 21.83
Solids 1.17 1.17 0.00 0.00 0.00 0.00
Hydrocarbons 0.470 0.000 2.048 1.578 1.578 0.471
Flow Number 34 35 31 32 36 33
T, C 200 243.42 243.42 243.43 486.73 243.43
Press., psig 400 400 400 400 400.00 400.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00
Enthalpy, kW -96.591 -5.06 -346.24 -266.80 -254.78 -79.69
Total Flow, kg/hr 23.4 1.17 96.89 74.66 74.66 22.30
Water, kg/hr 21.76 0.00 94.84 73.08 73.08 21.83
Solids 1.17 1.17 0.00 0.00 0.00 0.00
hydrocarbons 0.470 0.000 2.048 1.578 1.578 0.471
CA 02748477 2011-08-02
[78] Example 5: The following process simulation described in Figure 30
simulates a 600psi
system pressures. The graph in Figure 30 simulates the impact of the produced
water feed temperature
on the overall process performance. Hot produced water that includes solids
and bitumen
contaminates is typical to insitue oilsands thermal extraction facility like
SAGD. The graph shows that
for a constant heat flow, as the produced feed water temperature increases, so
the amount of produce
steam increases accordingly. The heat source 0' in the simulation was 12KW.
The driving steam 36
temperature was 900F. 80% of the steam 31 recycled to the heater as the
driving steam 36 while 20% is
discharged out of system at 283C Steam + hydrocarbons. The simulation shows
that for feed water at a
temperature of 20C, amount of 15.1kg of produced steam is generated. For
temperature of 100C,
17.4kg of produced steam is produced and for temperature of 220C, 22.4kg of
produced steam is
produced.
[79] Example 6: The following table simulates the process as described in
Figure 4 for insitue
oilsands thermal extraction facility like SAGD. The water feed is hot produced
water at 200C that
includes solids and bitumen. The heat source 0' for the simulation was 12KW
and the system pressure
600psi. The total Inflow of Water + solids + Bitumen of flow 47 was 22.5 kg.
79% of the steam 31
recycles as the driving steam 36 while 21% is discharged out of system at 294C
Steam + hydrocarbons.
In the simulation 4.9kw removed at the flash/condensation unit 42 and used to
pre-heat water feed 47.
The product was split from flow 31 (not shown on figure 4) replacing flow 46.
Flows 44 and 45 were
equal in this simulation.
Product (split
Flow Number 47 35 31 33 36 45 43 from 33)
T, C 200 294.91 294.91 294.91 471.55 253.81 253.81 294.91
Press., psig 600 600.00 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00 0.13 1.00
Enthalpy, kW -92.863 -4.76 -361.07 -285.24 -261.99 -274.01 -15.89 -75.82
Total Flow,
kg/hr 22.5 1.13 101.76 80.39 74.82 74.82 5.56 21.37
Water, kg/hr 20.925 0.00 99.64 78.72 74.82 74.82 3.90 20.92
Si02 1.125 1.13 0.00 0.00 0.00 0.00 0.00 0.00
hydrocarbons 0.450 0.000 2.118 1.673 0.000 0.000 1.668 0.445
CA 02748477 2011-08-02
[80] Example 7: The following table is a simulation results for the process
describes in
Figure 25. The water feed 1 is produced water from a SAGD separator and
includes solids and
hydrocarbons at a high temperature of 200C. The produced water 1 is mixed with
superheated steam 7
at approximately 900F. Recycled water 12 from scrubber 23 is recycled back to
the water feed 1. Solid
contaminates 3 are removed from separator 21. The produced steam 4 is divided
into two flows -
portion 6 of the produced steam (22%) at temperature of 285C and 600psi
pressure is recovered from
the system as the product for steam injection or any other use. The rest 78%
of the produced steam 5 is
cleaned in a wet scrubber with saturated water, potentially with additional
chemicals that can
efficiently removed silica and possibly other contaminates introduced with the
produced water (like
magnesium based additives, soda caustic and others). Water 9 is feed into the
scrubber 23 and the
scrubbed water 12 is continually recycled back to the stage of the steam
generation. The scrubbed
steam 8 is compressed by mechanical means or by steam ejector 24 to a heater
25. In the simulation a
12kw heater was used 25 to simulate bench scale laboratory facility. In a
commercial plant any heater
can be used. The system simulation pressure was 600psig. The superheated steam
7 is used as the
driving steam to drive the process. Another option to minimize the risk of
build-ups in the injection
piping is to recover the produce steam 6 from flow 8 (indicates on Figure 25
as flow 6A)
Flow Number 1 2 3 4 5 6 7 8 9 10 12
T, C 200 284.78 284.78 284.78 284.77 284.77 478.12 253.81 20.00 254.1311
253.81
Press., psig 600 600.00 600.00 600.00 600.00 600.00 600.00 600.00 600.00
601.4696 600.00
Vapor Fraction 0 1.00 0.00 1.00 1.00 1.00 1.00 1.00 0.00 1 0.00
Enthalpy, kW -74.2904 330.80 -3.82 326.94 255.03 -71.93 255.05 267.08 -13.25 -
267.046 -1.21
Total Flow,
kg/hr 18 92.53 0.90 91.63 71.47 20.16 72.92 72.93 3.00 72.9221 1.55
Water, kg/hr 16.74 90.01 0.00 90.01 70.21 19.80 72.92 72.93 3.00 72.92209 0.28
Solids 0.9 0.90 0.90 0.00 0.00 0.00 0.00 0.00 0.00 0 0.00
Hydrocarbons 0.360 1.618 0.000 1.618 1.262 0.356 0.000 0.000 0.000 6.99E-06
1.262
[81] Example 8: The following table is a simulation results for the process
describes in
Figure 26. The water feed 1 is produced water from a SAGD separator and
includes solids and
hydrocarbons at a high temperature of 200C. (The produced water 1 is at a much
lower flow of approx.
8kg/hour compared to the flow of 18kg/hour in example 25 because additional
treated boiler feed
water 10 is added later). The feed 1 is mixed with superheated steam 7 at
approximately 900F. Recycled
water 12 from scrubber 23 is recycled back to the water feed 1. Solid
contaminates 3 are removed from
CA 02748477 2011-08-02
separator 21. The produced steam 4 is divided into two flows - portion 6 of
the produced steam (75%)
at temperature of 271C and 600psi pressure is recovered from the system as the
product for steam
injection or any other use. The rest 25% of the produced steam 5 is cleaned in
a wet scrubber with
saturated water, potentially with additional chemicals to remove contaminates.
Water 9 at flow of
0.3kg/hour and temperature of 20C is feed into the scrubber 23 and the
scrubbed water 12 is
continually recycled back to the stage of the steam generation. The scrubbed
steam 8 is condensed by
direct contact with clean BFW 10 at flow of 10kg/hour and temperature of 20C.
The generated water 11
at temperature of 250C is pumped to low overpressure to generate circulation
and compensate for the
losses and generated into superheated steam by 12kw heater 25 to simulate
bench scale laboratory
facility. In a commercial plant any commercial boiler can be used to produce
the superheated dry
steam. The system simulation pressure was 600psig. The superheated steam 7 at
flow of 16kg/hour is
used as the driving steam to drive the process. Another option to minimize the
risk of build-ups in the
injection piping is to recover the produce steam 6 from flow 8 (indicates on
Figure 25 as flow 6A)
Flow No. 1 2 3 4 5 6
T, C 200.00 271.89 271.89 271.89 271.88 271.88
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0.00 0.99 0.00 1.00 1.00 1.00
Enthalpy, kW -32.47 -87.32 -1.66 -85.64 -21.42 -64.27
Total Flow, kg/hr 7.870 24.105 0.390 23.715 5.932 17.797
Water, kg/hr 7.320 23.500 0.000 23.500 5.879 17.636
Solids 0.390 0.390 0.390 0.000 0.000 0.000
Hydrocarbons 0.160 0.215 0.000 0.215 0.054 0.161
Flow No. 7 8 9 10 11 12
T, C 660.37 253.81 20.00 20.00 250.31 253.81
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 1.00 1.00 0.00 0.00 0.00 0.00
Enthalpy, kW -53.87 -21.71 -1.32 44.1606 -65.87 -1.04
Total Flow, kg/hr 15.927 5.927 0.300 10.000 15.927 0.305
Water, kg/hr 15.927 5.927 0.300 10.000 15.927 0.251
Solids 0.000 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.000 0.054
CA 02748477 2011-08-02
[82] Example 9: The following table is a simulation results for the process
describes in Figure
27. The simulation is similar to example 8 with change to the production of
the boiler feed water where
instead of using clean Boiler Feed water to condensate the generated steam for
generating the
superheated steam generator feed water, heat is recovered to condensed the
steam to BFW and
introduced back to the system to heat the feed water. By this arrangement the
need in fresh BFW is
eliminated and replaced by condensation. Water feed 1 is heated with Q-in that
is a heat recovered
from the condensation and mixed with superheated steam 7. Recycled water 12
from scrubber 23 is
recycled back to the water feed 1. Solid contaminates 3 are removed from
separator 21. The produced
steam 4 is divided into two flows - portion 6 of the produced steam (53%) at
temperature of 282C and
600psi pressure is recovered from the system as the product for steam
injection or any other use. The
rest 47% of the produced steam 5 is cleaned in a wet scrubber with saturated
water, potentially with
additional chemicals to remove contaminates. Water 9 at flow of 4.1kg/hour and
temperature of 20C is
feed into the scrubber 23 and the scrubbed water 12 is continually recycled
back to the stage of the
steam generation. The scrubbed clean steam 8 is condensed by recovering the
condensation heat Q-out
that is return back to the system for pre-heating the feed water as Q-in or
for pre-heating other streams
like 9. The generated water 11 at temperature of 254C is pumped to low
overpressure to generate
circulation and compensate for the losses and generated into superheated steam
by 12kw heater 25 to
simulate bench scale laboratory facility. In a commercial plant any commercial
boiler can be used to
produce the superheated dry steam. The system simulation pressure was 600psig.
The superheated
steam 7 at flow of 18.7kg/hour is used as the driving steam to drive the
process. Another option to
minimize the risk of build-ups in the injection piping is to recover the
produce steam 6 from flow 8
(indicates on Figure 25 as flow 6A)
Flow No. 1 2 3 4 5 6
T, C 200.00 282.56 282.56 282.56 282.52 282.52
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0.00 0.99 0.00 1.00 1.00 1.00
Enthalpy, kW -86.378 -145.07 -4.46 -140.57 -66.07 -74.51
Total Flow,
kg/hr 20.930 40.518 1.050 39.468 18.552 20.920
Water, kg/hr 19.460 38.678 0.000 38.678 18.180 20.501
Solids 1.050 1.050 1.050 0.000 0.000 0.000
Hydrocarbons 0.420 0.791 0.000 0.791 0.372 0.419
Flow No. 7 8 9 11 12
T, C 493.17 253.81 20.00 253.81 253.81
CA 02748477 2011-08-02
Press., psig 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 1.00 1.00 0.00 0.00 0.00
Enthalpy, kW -65.12 -68.38 -4.42 -77.12 -2.11
Total Flow,
kg/hr 18.671 18.671 1.000 18.671 0.881
Water, kg/hr 18.671 18.671 1.000 18.671 0.509
Solids 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.372
[83] Example 10: The following table is a simulation results for the process
describes in
Figure 28. The water feed 1 is tailings water from an open mine oilsands
extraction facility. The feed
water includes 30% solids and 3% solvents at low temperature of 20C. The
system is low pressure, close
to atmospheric pressure. The produced water 1 is mixed with superheated steam
7 at 535C. Solid
contaminates 3 are removed from separator 21. The produced steam 4 is divided
into two flows -
portion 5 of the produced steam (70%) at temperature 99.7C is recycled, using
mechanical
compression, ejector (not shown) or any other means to generating the recycle
flow. The recycled
steam 5 is heated with 12kw heat source to generate superheat steam 7 at
temperature of 534C. The
rest 30% of the produced steam 8 is condensed by direct contact mixture with
process water 9 at
temperature of 20C to generate 80C process water that can used in the
extraction process. The
produced steam 4 can be furthered clean with any dry or wet commercial
available cleaning systems,
like a wet scrubber (not shown) with saturated water, possibly with additional
chemicals to remove
contaminates. This cleaning can prevent build-ups at the recycling low
pressure compressing unit and
the heating unit 25. A total of 206 kg/hour hot water is generated at this
simulation from 12kw heat
sorce.
Flow Number 1 2 3 4 5 6
T, C 20.00 99.73 99.73 99.73 99.73 108.00
Press., atm 1.00 1.00 1.00 1.00 1.00 1.10
Vapor Fraction 0.00 0.88 0.00 1.00 1.00 1.00
Enthalpy, kW -132.07 -293.79 -41.37 -248.71 -174.10 -173.88
Total Flow,
kg/hr 30.00 78.84 9.00 69.84 48.89 48.89
Water, kg/hr 20.10 66.85 0.00 66.85 46.79 46.79
Solids 9.00 9.00 9.00 0.00 0.00 0.00
N-Butane 0.45 1.50 0.00 1.50 1.05 1.05
CA 02748477 2011-08-02
N-Pentane 0.32 1.05 0.00 1.05 0.73 0.73
N-Hexane 0.14 0.45 0.00 0.45 0.31 0.31
Flow Number 7 8 9 10 11
T, C 534.94 99.73 20.00 80.11 80.11
Press., atm 1.00 1.00 1.00 1.00 1.00
Vapor Fraction 1.00 1.00 0.00 1.00 0.00
Enthalpy, kW -161.88 -74.61 -821.39 -0.61 -895.39
Total Flow,
kg/hr 48.89 20.95 186.00 0.51 206.44
Water, kg/hr 46.79 20.05 186.00 0.10 205.95
Solids 0.00 0.00 0.00 0.00 0.00
N-Butane 1.05 0.45 0.00 0.26 0.18
N-Pentane 0.73 0.31 0.00 0.12 0.20
N-Hexane 0.31 0.13 0.00 0.03 0.11
[84] Example 11: The following table is a simulation results for the process
describes in
Figure 29. The water feed 1 is tailings water from an open mine oilsands
extraction facility. The feed
water includes 30% solids and 3% solvents at low temperature of 20C. The
system is low pressure, close
to atmospheric pressure. The produced water 1 is mixed with superheated steam
7 at 492C. Solid
contaminates 3 are removed from separator 21. The produced steam is condensed
by direct contact
mixture with process water 9 at temperature of 20C to generate 80C process
water that can use in the
extraction process. Portion of the produced water is heated in boiler 25 to
generate superheated
steam. The flow to produced the steam 5 can be further treated to remove
contaminates to increase its
quality to BFW quality water. Another option is to split the produce steam 4,
scrub portion, condensed
the clean scrubbed steam to water, possibly with water from an exterior source
and used the clean
condensate to generate the super heated steam 7. This option was described in
other figures but is not
reflected in the current simulation.
Flow No. 1 2 3 4 5 6
T, C 20 110.46 110.46 110.46 80.07 80.07
Press., atm 1 1.00 1.00 1.00 1.00 1.10
Vapor Fraction 0 1.00 0.00 1.00 0.00 0.00
Enthalpy, kW 20.3134 -68.23 -2.51 -65.72 -59.92 -59.92
Total Flow,
kg/hr 6 19.80 1.80 18.00 13.80 13.80
Water, kg/hr 4.02 17.81 0.00 17.81 13.79 13.79
CA 02748477 2011-08-02
Solids 1.8 1.80 1.80 0.00 0.00 0.00
Hydrocarbons 0.180 0.194 0.000 0.194 0.015 0.015
Flow No. 7 8 9 10 11
T, C 492.40 80.07 20.00 80.07 80.07
Press., atm 1.00 1.00 1.00 1.00 1.00
Vapor Fraction 1.00 0.00 0.00 1.00 0.00
Enthalpy, kW -47.91 -803.20 -737.48 0.00 -743.28
Total Flow,
kg/hr 13.80 185.00 167.00 0.00 171.20
Water, kg/hr 13.79 184.81 167.00 0.00 171.02
Solids 0.00 0.00 0.00 0.00 0.00
Hydrocarbons 0.015 0.194 0.000 0.000 0.180
[85]
[86]
