Canadian Patents Database / Patent 2770651 Summary

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(12) Patent Application: (11) CA 2770651
(54) English Title: STEAM GENERATION
(54) French Title: PRODUCTION DE VAPEUR
(51) International Patent Classification (IPC):
  • F22B 37/26 (2006.01)
  • E21B 43/24 (2006.01)
(72) Inventors :
  • BETZER, MAOZ (Canada)
(73) Owners :
  • BETZER, MAOZ (Not Available)
(71) Applicants :
  • BETZER, MAOZ (Canada)
(74) Agent:
(74) Associate agent:
(45) Issued:
(22) Filed Date: 2012-02-29
(41) Open to Public Inspection: 2013-03-12
Examination requested: 2017-02-13
(30) Availability of licence: N/A
(30) Language of filing: English

(30) Application Priority Data:
Application No. Country/Territory Date
2752558 Canada 2011-09-12

English Abstract



The present invention is a system and method for steam production for oil
extraction. The method
includes generating steam, heating contaminated water and solid particles,
flashing the contaminated
water, separating contaminate and solid particles, and using the generated
steam for oil recovery. The
water feed of the present invention can be hot produced water separated from a
produced oil emulsion
and/or low quality water salvaged from industrial plants, such as refineries
and tailings from an oilsands
mine.


Note: Claims are shown in the official language in which they were submitted.


CLAIMS

I claim:


1. A method for steam production for extraction of oil, said method comprising
the steps of
heating liquid water having contaminates in a non-direct heat exchanger;

flashing heated liquid water so as to transfer said liquid water from a liquid
phase to a gas
phase; and

using said gas phase for oil recovery.


2. A method for steam production for oil production, said method comprising
the steps of:
mixing contaminated liquid water with solid particles heaving heat capacity;

heating said mixture of contaminated water in an heat exchanger under
controllable
pressure to prevent water phase change from liquid to gas; and

reducing the pressure of said heated mixture to flash liquid water to gas
phase;
separating said solid particles; and

recovering produced steam.


3. A system for producing steam for extract heavy bitumen, the system
comprising vertical vessel
for generating steam that includes:

a bottom section for solids discharge;

a steam injection section for injecting superheated steam located above said
solid
discharge section where said superheated steam flows upwards;

a contaminated water injection section located above the superheated steam
injection
section for injection said contaminated liquid water into the up flowing
superheated steam, and;

a steam discharge section located above said water injection section for
discharge the
produced steam.


68

Note: Descriptions are shown in the official language in which they were submitted.


CA 02770651 2012-02-29
STEAM GENERATION
BACKGROUND OF THE INVENTION

[01] This application relates to a system and method for producing steam from
a 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 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 for the mining oilsands industry. The high pressure
drive steam is generated
using a commercially available, non-direct steam boiler, co-gen, Once Through
Steam Generator (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 a combustion gas fired Direct Contact Steam
Generator (DCSG) for
consuming liquid waste streams or with distillation water treatment systems.
[02] The injection of steam into heavy oil formations has proven to be an
effective method for
FOR and it is the only method currently used commercially for recovery of
bitumen from deep
underground oilsands formations in Canada. It is known that FOR can be
achieved when combustion
gases, mainly CO2, are injected into the formation, possibly with the use of a
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 CO2. Another
option to address these concerns and generate steam from low grade produced
water with Zero Liquid
Discharge (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,
etc. 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 chemicals. The Steam Drive - Direct Contact Steam Generator (SD-DCSG)
can consume the
contaminated water feed for generating steam. The SD-DCSG can be a standalone
system or can be
integrated with a combustion gas DCSG, as described in this application. The
proposed SD-DCSG is also
suitable for oilsands mining projects where the Fine Tailings (FT) or Mature
Fine Tailings (MFT) are
heated and converted to solids and steam using the driving steam energy. The
produced steam from the
1


CA 02770651 2012-02-29

SD-DCSG can be used to heat the process water in a direct or non-direct heat
exchange. The hot process
water is mixed with the mined oilsands ore during the extraction process.
[03] The method, as described, includes generating additional steam from
highly contaminated
oily water with an option for zero liquid waste discharge. Superheated steam
from an industrial boiler is
used as the driving force for generating additional steam in a direct contact
heat transfer with the
contaminated water. Fine Tailings from tailing ponds can be also used. A
"tailor made" pressure and
temperature steam, as required for injection into the underground oil bearing
formation, is generated. This
process allows for generation of additional lower temperature steam from waste
water in a high efficiency
energy process. The amount of additional steam generated increases with the
temperature of the driving
steam, and with the reduction of the pressure of the formation. For low
pressure shallow formations, more
steam can be produced in comparison to deep, high pressure formations. Another
option is to recycle a
portion of the produced steam through a heater and use it as the driving
steam, and thereby minimizing
the need for external steam as a heat energy source. A portion of the oil
component in the water feed will
be converted into hydrocarbon gas, basically serving as a solvent. Additional
solvents can be added and
injected with the steam to improve the oil recovery. The presented technology
has a high thermal
efficiency capable of consuming contaminated hot produced water, without the
need to reduce the heat to
allow effective water treatment. The process can convert the existence of oil
contaminates within the feed
water into an advantage by generating solvent. This steam generation direct
contact facility can be located
in close proximity to the SAGD pads to use the hot produced water and inject
the produced steam into the
injection wells.
[04] The steam for the SD-DCSG can be provided directly from a power station.
The most
suitable steam will be medium pressure, super-heated steam as is typically fed
to the second or third stage
of steam turbine. A cost efficient, hence effective system will be used 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 superheated 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 to
generate injection steam for an 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.
[05] The definition of "Steam Drive - Direct Contact Steam Generation" (SD-
DCSG) is that
steam is used to generate additional steam from a 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
2


CA 02770651 2012-02-29

steam gases). In the SD-DCSG, the driving steam pressure is similar to the
combustion pressure and the
produced steam is a mixture of the two.
[06] The driving steam is generated in a Non-Direct Steam Generator (like a
steam boiler with
a steam drum and a mud drum) or in a "Once Through Steam Generator" (OTSG)
COGEN that uses the
heat from a gas turbine to generate steam, or in 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.
[07] The excessive energy in the superheated steam is used for generating
additional lower
temperature steam for injection into the formation. The use of evaporation
water treatment facilities in the
oilsands industry allows for the production of superheated steam. The proposed
method uses Direct
Contact Steam Generation where the superheated steam gas is in direct contact
with the liquid produced
water. Hydrocarbons, like solvents, within the produced water will be directly
converted to gas and
recycled back to the formation, possibly with additional solvents that can be
added to the steam flow. The
method generates a "tailor made" pressure and temperature steam, as required
for injection into the
underground oil bearing formation while maximizing the amount of the generated
steam. The simulation
in this application shows that for a 263psi system with a constant feed of 25
C water flow at 1000
kg/hour, there is a need for 12.9tons/hour of 300 C steam to gasify 1 ton/hour
of liquid water. When
higher temperature (500 C) driving steam is used, there is a need for only
4.ltons/hour of steam. The
example simulation results show that the amount of produced steam increases by
314% with an increase
in the driving steam temperature. The pressure impact simulation was based on
driving steam being at a
constant temperature of 450 C and with one ton/hour of 25 C water feed. The
simulation shows that at
pressure of 263psi, 4.9tons/hour of driving steam is used to gasify the water
feed. At a higher pressure of
1450psi, 5.1 tons/hour driving steam will be used. The results show that a
pressure increase slightly
reduces the amount of produced steam. The impact of the feed water temperature
on the system
performance was also simulated. It was shown that for a system of constant
12kw heat source at 600psi,
15.1 kg/hour of feed water was gasified to generate injection steam. When the
produced water
temperature was 220 C, 22.4kg/hour was gasified. This shows that the produced
water temperature has a
large impact on the overall performance and that by using the high temperature
produced water, the
system performance can be increased by close to 150%. The simulation shows
that hydrocarbons, like
solvents with the produced water, will be converted to gas and injected with
the steam. The system can
also include a heater to recycle a portion of the produced steam as the
driving steam that will be produced
locally. There was also shown to be an advantage to using hot produced water
and minimizing the
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CA 02770651 2012-02-29

produced steam pressure drop. This can be achieved by locating the system
close to the injection and
production well pad. Make-up steam supplied from a remote steam generation
facility can be used to
operate a steam ejector with a local steam heater, or be used as the
superheated driving steam. The system
is ZLD in nature. It can also produce liquid waste if liquid disposal is
preferred. The superheated steam
can be generated by heating steam or by reducing the pressure of saturated
steam during or before the
stage of mixing the steam with the low quality water.
[08] 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 blow-down heat as the
heat source for water distillation of de-oiled produced water in a single
stage MVC water distillation unit.
The concentrated blow-down from the distillation unit can be treated in a
crystallizer to generate solid
waste.
[09] 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 includes 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 for
disposal or to a multi stage evaporator to recover most of the water and there
generates a ZLD 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 the 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 a higher temperature due to the direct mixture with the
superheated dry steam that
converts the liquid into gas and solids.
[10] 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 formations 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).
[11] US patent No. 6,733636, issued to Heins on May 11, 2004, describes a
produced water
treatment process with a vertical MVC evaporator.

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[12] US Patent No. 7,578,354, issued to Minnich et al. on August 25, 2009,
describes the use
of Multi Effect Distillation (MED) for generating steam for injection into an
underground formation.
[13] US Patent No. 7,591,311, issued to Minnich et al. on September 22, 2009,
describes a
process of 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 into the
produced steam. The solids and
possibly volatile organic remains are carried with the steam to the
underground oil formation. The
concentrated brine is discharged in liquid form.
[14] US Patent No. 4,398,603, issued to Rodwell on August 16, 1983, describes
producing
steam from a low quality feed water. Superheated steam is introduced into
liquid water in a vessel. The
mixture is done in a liquid environment where minerals (solids) are
participates and are removed in a
liquid phase from the vessel by withdrawing a waste water stream. Due to the
excess heat within the
superheated steam, a portion of the liquid feed water evaporates and produces
saturated steam. Because
all mixing with the steam is done in a liquid environment, the process can
only produce saturate (wet)
steam with waste liquid discharge for removing the solids.
[15] This invention's method and system for producing steam for extraction of
heavy bitumen
includes the steps as described in the patent figures.
[16] The advantage and objective of the present invention are described in the
patent
application and in the attached figures.
[17] 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

[18] Steam injection is currently the only method commercially used on a large
scale for
recovering oil from deep (non-minable) oil sands formations. Sometimes
additional solvents are used,
mainly hydrocarbons. There are a few disadvantages to the existing steam
generation methods. For
example, the steam is much cleaner than is needed for injection. To achieve
the water quality currently
used for steam injection, the water is extensively treated - the first stage
is to separate the oil and de-
oiling. To achieve that, the produced water is cooled to a temperature at
which it can efficiently be de-
oiled to the water treatment plant feed specifications where it is treated to
the boiler feed water
specifications. The need to cool the water decreases the SAGD's overall
efficiency. In recent year there


CA 02770651 2012-02-29

has been a shift toward the use of evaporator water treatment technologies
instead of softening based
technologies. As a result, due to the higher quality of the produced water, it
is possible to increase the
produced steam temperature and pressure. There are other advantages to the use
of evaporators to treat the
produced water, such as the ability to use brackish water with high levels of
salts and incorporate a
crystallizer to achieve ZLD. The proposed method intends to use the systems
and methods developed for
combustion of low quality fuel in gas driven Direct Contact Steam Generation
(DCSG) and to replace the
combustion gas driving fluid with steam, where additional steam is generated
by a direct mixture of liquid
with superheated steam gas, resulting in a relatively low cost steam achieved
by a Steam Drive DCSG.
[19] The method and system of the present invention for steam production (for
extraction of
heavy bitumen by injecting the steam into 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
containing 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) Using the generated steam for EOR, possibly by
injecting the produced steam into
an underground oil formation through SAGD or CSS steam injection wells.
[20] The presented method and its associated system can be applied to many
existing oilsands
operations. Due to the minimal water treatment requirements and the fact that
the feed water can be at
higher temperatures, it is possible to produce additional steam close to the
production and the injection
wells, on the well pad. The high temperature of the feed water is an advantage
as this heat energy helps in
the production of steam and minimizes the amount of superheated driving steam
consumed. It is possible
to operate the SD-DCSG in a ZLD mode where the solids contaminates are
extracted in a dry, semi-dry
stable form. A ZLD facility is more environmentally friendly compared to a
system that generates reject
water and sludge. However, it is also possible to operate the SD-DCSG in
liquid waste discharge mode
(liquid discharge mode can be used if disposal caverns or disposal wells are
available and are approved
for disposal usage by the regulators, like the Energy Resources Conservation
Board (ERCB) in Alberta,
Canada). The invention method can also be operated in a liquid waste discharge
mode. This can be done
by adjusting the ratio between the produced water and the driving superheated
steam and increasing the
water feed flow or decreasing the superheated driving steam flow. The water
feed of this method and
system for enhanced oil recovery can be water separated from produced oil
and/or low quality water
salvaged from industrial plants, such as refineries, and tailings as make-up
water. Both of the above will
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CA 02770651 2012-02-29

allow oilsands operations to more easily meet environmental regulations
without radical changes to oil
recovery and water recycling technologies currently in use.
(21] The excessive energy in superheated steam can be used for generating
additional lower
temperature steam for injection into the formation. The use of evaporation
water treatment facilities in the
oilsands industry allows for the production of superheated steam. The proposed
method uses Direct
Contact Steam Generation where the superheated steam gas is in direct contact
with the liquid produced
water. Hydrocarbons, like solvents, within the produced water will be directly
converted to gas and
recycled back to the formation, possibly with additional solvents that can be
added to the steam flow. The
presented technology generates a "tailor made" pressure and temperature steam,
as required for injection
into the underground oil bearing formation while maximizing the amount of the
generated steam. The
simulation shows that for a 263psi system with a constant feed 25 C water flow
at 1000kg/hour, there is a
need for 12.9tons/hour of 300 C steam to gasify Iton/hour of liquid water.
When higher temperature
(500 C) driving steam is used, there is a need for only 4.1tons/hour of steam.
The results show that the
amount of produced steam increases by 314% with a driving steam temperature
increase. The pressure
impact simulation was based on driving steam at a constant temperature of 450
C and Iton/hour 25 C
water feed. The simulation shows that at pressure of 263psi, 4.9tons/hour of
driving steam is used to
gasify the water feed. At a higher pressure of 1450psi, 5.1 tons/hour driving
steam will be used. The
results show that a pressure increase slightly reduces the amount of produced
steam. The impact of the
feed water temperature on the system performance was also simulated. It was
shown that for a system of a
constant 12kw heat source at 600psi, 15.1kgs/hour of feed water was gasified
to generate injection steam.
Where the produced water temperature was 220 C temperature, 22.4kg/hour was
gasified. This shows
that the produced water temperature has a large impact on the overall
performance and that by using the
high temperature produced water, the system performance can be increased by
close to 150%. The
simulation shows that hydrocarbons, like solvents with the produced water,
will be converted to gas and
injected with the steam. The system can also include a heater to recycle a
portion of the produced steam
as the driving steam that will be produced locally. There was shown to be an
advantage to using hot
produced water and to minimizing the produced steam pressure drop. This can be
achieved by locating
the system close to the injection and production well pad. Make-up steam
supplied from a remote steam
generation facility can be used to operate a steam ejector with a local steam
heater, or be used as the
superheated driving steam. The system can be ZLD. It can also produce liquid
waste if liquid disposal is
preferred.
[22] 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
a non-direct heat
exchanger; (2) Using the generated steam as the hot gas to operate a DCSG
(Direct Contact Steam
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CA 02770651 2012-02-29

Generator); (3) Mixing the super heated steam gas with liquid water containing
significant levels of
solids, oil contamination and other contaminates; (4) Directly converting
liquid phase water into the 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 the 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,
sodium phosphates, lignin
sulfonates, sodium hydroxide, sodium silicate or any other commercially
available chemicals) can be
added to the wet scrubber to remove contaminates from the steam flow. The
solids removed from the
system are at temperature close to the produced steam temperature. The heat
within the produced solids in
a slurry form can be used to dry the produced solids further in low pressure
air where water vapor will be
removed. If the hot solids are removed in a dry form, additional tailings can
be added to the hot solids to
evaporate some of the water within the additional tailings and to generate a
stable slurry while minimizing
dust from dry solids.
[23] In another embodiment, part of the generating steam is condensed and used
to wash the
produced steam of solid particles in a wet scrubber. Chemicals can be added to
the liquid water to remove
contaminates. To prevent solids accumulation a portion of the liquid water is
recycled back and mixed
with the superheated steam to transfer it into gas and solids. A portion of
the scrubber liquid water can
also mixed with the discharged solids from the DCSG. A portion of 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.
[24] In another embodiment, the scrubbed saturated steam, after the solids are
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.
[25] In another embodiment, the SD-DCSG is integrated with a 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.
[26] The present invention system and process will be controlled during start-
up and operation
to maintain temperatures, pressures, flows and any other process element that
is described in this
invention.

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[27] The present invention can be used to treat contaminated water using the
SD-DCSG in
different industries, such as the power industry or chemical industry where
there is a need to recover the
water from a contaminated water stream to generate steam with zero liquid
discharge.
[28] The system and method's different aspects of the present invention are
clear from the
following figures.

BRIEF DESCRIPTION OF THE DRAWINGS

[29] FIGURES 1, IA, 113, 1C, ID, 1E, 2A1A, 2A1B, 2A2A and 2A2B show the
conceptual
flowchart of the method and the system.
[30] FIGURE 2 shows a block diagram of an embodiment of the invention.
[31] FIGURE 2A shows a schematic of a vertical SD-DCSG.
[32] FIGURE 2A1 shows a schematic of a vertical SD-DCSG as described in FIGURE
2A
with particles circulation.
[33] FIGURE 2A2 shows a schematic of a vertical SD-DCSG as described in FIGURE
2A1
with a heater for heating the low quality water flow and circulated particles.
[34] FIGURE 2B shows a block diagram of the embodiment of the invention.
[35] FIGURE 2C is schematic view of another embodiment of a reaction chamber
apparatus
of a high-pressure steam drive direct contact steam generator of the present
invention.
[36] FIGURE 2C1 shows a schematic of a vertical rotating SD-DCSG as described
in
FIGURE 2C with particles circulation as described in FIGURE 2A2.
[37]
[38] FIGURE 2D shows a schematic view of another embodiment of a vertical SD-
DCSG.
[39] FIGURE 2E shows a schematic view of a SD-DCSG integrated into an open
mine
oilsands extraction plant.
[40] FIGURE 2F shows a schematic view of a SD-DCSG with a non-direct heat
exchanger to
heat the process water.
[41] FIGURE 3 is a schematic view of an illustration of one embodiment of the
present
invention without using an external water source for the driving steam.
[42] FIGURE 3A is a schematic view of an illustration of another embodiment of
the present
invention.
[43] FIGURE 3B is a schematic view of an illustration of a parallel flow SD-
DCSG according
to Figure 3A.
[44] FIGURE 3C is a schematic view of an illustration of a SD-DCSG with a
stationary
enclosure and an internal rotating element.

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[45] FIGURE 3D is a schematic view of an illustration of a modification of
Figures 3C and 3B
for a steam drive Non-Direct contact steam generator.
[46] Figure 3E shows a schematic view of a parallel flow and a counter flow
steam drive
direct contact steam generation system.
[47] Figure 3F shows a schematic view of a direct contact steam generating
system as shown
in Figure 3E with solids separation.
[48] FIGURE 3G is a schematic view of a steam drive direct contact steam
generator
apparatus.
[49] FIGURE 3H is a schematic view of another configuration of a steam drive
direct contact
steam generator apparatus.
[50] FIGURE 31 is a schematic view of a steam drive direct contact steam
generator
apparatus.
[51] FIGURE 3J is a schematic view of a steam drive direct contact steam
generator with an
internal wet scrubber that generates additional wet solids free steam.
[52] FIGURE 3K is a schematic view of an illustration of another embodiment of
the present
invention.
[53] FIGURE 3K1 illustration a SD-DCSG as described in Figure 3K with the use
of pre-
heater and spherical bodies circulation.
[54] FIGURE 4 is a schematic view of an illustration of still another
embodiment of the
present invention.
[55] FIGURE 5 is a schematic diagram of one embodiment of the invention that
generates wet
scrubbed, clean saturated steam.
[56] FIGURE 5A is a schematic view of an illustration of one embodiment of the
invention
where a portion of the driving steam water is internally generated.
[57] FIGURE 5B is a schematic view of the invention with internal distillation
water
production for the boiler.
[58] FIGURE 5C is a schematic diagram of a method that is similar to Figure 5B
but with a
different type of SD-DCSG.
[59] FIGURE 6 is a schematic diagram of the present invention which includes a
SD-DCSG
and an FOR facility.
[60] FIGURE 6A is a schematic flow diagram of the integration between SD-DCSG
and
DCSG that uses the combustion gas generated by the pressurized boiler.
[61] FIGURE 6A1 shows a schematic diagram of the present invention as
described in
FIGURE 6 with a produced water pre-heater.



CA 02770651 2012-02-29

[62] FIGURE 6A2 shows a schematic diagram of the present invention as
described in
FIGURE 6A1 with a separate closed loop produced water pre-heater.
[63] FIGURE 6A3 shows a more detailed diagram of the present invention as
described in
FIGURE 6A1 with additional details on the steam generation facility.
[64] FIGURE 6B is a schematic view of a direct contact steam generator with
rotating
internals, dry solids separation, wet scrubber and saturated steam generator.
[65] FIGURE 6Cis a schematic view of a SD-DCSG and heavy oil extraction
through steam
injection.
[66] FIGURE 6D shows a schematic view of a SD-DCSG similar to the system in
Figure 6C.
[67] FIGURE 6E is a schematic view of the SD-DCSG with similarities to Figure
6D and with
externally supplied make-up HP steam.
[68] FIGURE 6F shows a schematic view of another embodiment of the present
invention for
generating steam for oil extraction with the use of a steam boiler and steam
heater.
[69] FIGURE 6G shows a schematic view of natural gas boiler with super heater
and SD-
DCSG for generating steam for oil extraction.

[70] FIGURE 7 is a schematic view of an integrated facility of the present
invention with a
commercially available steam generation facility and for FOR for heavy oil
production.
[71] FIGURE 8 is a schematic view of the invention with an open mine oilsands
extraction
facility.
[72] FIGURE 9 is another schematic view of the invention with an open mine
oilsands
extraction facility and a pressurized fluid bed boiler.
[73] FIGURE 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG.
[74] 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.
[75] FIGURE 1IA is a schematic view of the present invention that includes a
steam
generation facility, SD-DCSG and MED water treatment plant.
[76] FIGURE 11 B is a schematic diagram of the present invention that includes
a steam drive
DCSG with a direct heated Multi Stage Flash (MSF) water treatment plant and a
steam boiler for
generating steam for EOR.
[77] FIGURE 12 is a schematic view of an illustration of the use of a partial
combustion
gasifier with the present invention for the production of syngas.
[78] FIGURE 13 is a schematic view of the present invention for the generation
of hot water
for oilsands mining extraction facilities.

11


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[79] FIGURE 13A is a schematic view of the process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
[80] FIGURE 13B is a schematic view of the process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
[81] FIGURE 14 is a schematic view of one illustration of the present
invention for the
generation of pre-heated water.
[82] FIGURE 15 is a schematic view of the invention with an open mine oilsands
extraction
facility.
[83] FIGURE 16 is a another schematic view of the invention with another open
mine oilsands
extraction facility.
[84] FIGURE 17 is a schematic view of the invention with still another open
mine oilsand
extraction facility.
[85] FIGURE 18 is a schematic view of the invention with yet another open mine
oilsands
extraction facility.
[86] FIGURE 19 is a schematic view of an illustration of still another
embodiment of the
present invention.
[87] FIGURE 20 is a schematic view of an illustration of yet another
embodiment of the
present invention.
[88] FIGURE 21 is a schematic view of an illustration of a boiler, steam drive
DCSG, solid
removal and Mechanical Vapor Compression distillation facility for generating
distilled water in the
boiler for steam generation.
[89] Figure 22 is a graph illustration of a simulation of the process as
described in Figure 2A.
[90] Figure 23 is another graph illustration of a simulation of the process as
described in
Figure 2A.
[91] Figure 24 is yet another graph illustration of a simulation of the
process as described in
Figure 2A.
[92] Figure 25 is a schematic view of the process of Example 7.
[93] Figure 26 is a schematic view of the process of Example 8.
[94] Figure 27 is a schematic view of the process of Example 9.
[95] Figure 28 is a schematic view of the process of Example 10.
[96] Figure 29 is a schematic view of the process of Example 11.
[97] Figure 30 is a graph illustration showing the amount of produced steam as
a function of
the feed water temperature in the system.

12


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DETAILED DESCRIPTION OF THE DRAWINGS

[98] FIGURES 1, lA, IB, IC, ID, IE, 2AIA, 2A1B, 2A2A and 2A2B show the
conceptual
flowchart of the method and the system.
[99] FIGURE 2 shows a block diagram of an embodiment of the invention. Flow 9
is
superheated steam. The steam pressure can be from 1 to 150 bar and the
temperature can be between
150 C and 600 C. The steam flows to enclosure 11, which is a SD-DCSG.
Contaminated produced water
7, possibly with organic contaminates, and 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 because 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 of the steam at the pressure inside enclosure 11. The produced
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.
[100] FIGURE 2A shows a schematic of a vertical SD-DCSG. Dry steam 9 is
injected into
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 a 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 treated.
[101] FIGURE 2A1 shows a schematic of a vertical SD-DCSG as described in
FIGURE 2A
with particles circulation. Spherical particles 15 are added to the low
quality water feed 17. The low
quality water can include oilsands FT, MFT or any type of low quality water
like produced water from
SAGD, CSS. The spherical particles can be composed of metal, ceramic
(preferably in the form of balls),
composite organic or natural rock aggregates, sand or any other naturaly
occurred or crushed unorganic
material. The particles can be made of alloy metals that includes catalysts
that can help with contaminates
removals. The FT and the spheres mixture 7 injected into the DCSG 11 where it
is mixed with
superheated steam 9. The liquid water phase evaporates to steam and the
remaining solids, together with
the round spheres 12 discharged from the bottom of the DCSG 1. The solids are
separated with any
commercially available separation system 13 that can use rotating screen,
vibrating screen, magnetic
separator, cyclone etc. The solid contaminates introduced with the low quality
water feed 14 are removed
13


CA 02770651 2012-02-29

for disposal or further treatment. The separated spherical particles 15 are
recycled back and mixed with
the low quality water 17. The presents of the spherical particles helps with
mixing the liquids 7 and steam
9 and with mobilizing the solids within the low quality water 17. A make up
solid particles can be added
to the recycled solids 15 to replace particles that were lost with the waste
stream 14. This is particularly
important when low cost natural solids are used like sand, crushed aggregates
and similar available
materials.
[102] FIGURE 2A2 shows a schematic of a vertical SD-DCSG as described in
FIGURE 2A1
with an heat exchanger or heater for heating the low quality water flow (like
tailings) and circulated
spherical particles. Spherical particles 15 are added to the low quality water
feed 17. The solid particles
15 can be composed of metal, ceramic or other available spherical particles
with high heat capacity. The
spherical particle reduces the amount of liquid water by replacing some liquid
contaminated water volum
with the spherical particles volume. The spherical particles are capable to
accumulate heat, especially if
they are made of metal like aluminum, copper, bronze and similar. The heat
capacity that was
accumulated at the heat exchanger / heater 19 will be released in the DCSG
helping transferring the water
phase from a liquid phase to a gas phase. There are few designed for heat
exchangers that can be used to
heat the mixture of spherical particles 15 and the contaminated water. The
amount of superheated driving
steam 9 will be minimized as the amount of liquid water will be reduced and
portion of the heat will be
supplied in the heater 19 and captured within the contaminate water feed and
the spherical particles. The
pressure in the heat exchanger 19 is preferably higher than the pressure in
the DCSG 11. This higher
pressure allows the heating of the contaminated water and the spherical bodies
to a higher temperature
without water phase change that will block the heat exchanger 19. This extra
heat at the lower pressure
flashes the liquid water. The liquid water changes to steam in vessel 11 as
the pressure in 11 is lower than
the pressure of flow 18 that flows through the heater. In 11 the pressure
drops, the water changes phase to
steam and the accumulating solids removed from the bottom of 11. For open mine
oilsands plants the
generated steam 8 can be directly mixed 21 and condensed into the extraction
water 20 for generating hot
extraction water 22. The hot extraction water is used in the prior art bitumen
extraction plants that are
operating in the Fort McMurray area from the late 60'.
[103] FIGURE 2B shows a block diagram of the invention. This figure is similar
to Figure 2
but contains 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 represented. High temperature filters, that can
withstand the steam's
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
14


CA 02770651 2012-02-29

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.
[104] 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 remove solids build-up. Any other design
that includes internal
embodiments that are free to move or that are moving with the rotating
enclosure and continually lifting
solids and liquids to enhance their mixture with the flowing gas can be used
as well. The drum 10 is a
pressure vessel which 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
bum any available fuel like
natural gas, 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 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 200 C and 800 C. 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 and 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
become 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 rotating
movement can agglomerate the solids into small spheres to increase the solids
stability and minimize dust
generation. The heat transfer in section 3 is sufficient to provide a
homogenous mixture of gas steam


CA 02770651 2012-02-29

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.
[105]
[106] FIGURE 2C1 shows a schematic of a vertical rotating SD-DCSG as described
in
FIGURE 2C integrated into a system as described in FIGURE 2A2. A rotating SD-
DCSG 3 include
lifting elements 10 that are capable of lifting solids, slurry and liquids and
mixing them with a flow of
superheated steam 8. Spherical particles 14 are added to the low quality water
feed 17 that can include
oilsands FT, MFT or any type of low quality water like produced water. Fluid
17 can be pre-heated(not
shown). The spherical particles can be composed of metal, ceramic or any other
type of aggregate,
preferably in the form of rounded solid particles. They are pumped using
piston pump, progress cavity
pump 18 or any other type of pump that can pump the slurry and the solid
particles mixture. The pumped
pressurized mixture flow through a suitable commercially available heat
exchanger 20 that uses steam or
thermal oil 21 in an indirect heat exchange. Few commercially available heat
exchanger design for slurry
can be used. One example is a self-cleaning heat exchanger of any self
cleaning technology like
circulating fluidized bed exchangers or heat exchangers with an on-line
cleaning circulating balls, where
the spherical balls 14 are also used as the circulation balls for cleaning the
heat exchanger. The heated
slurry and spheres mixture 9 injected into section 4 in the SD-DCSG 3. The
pressure in the DCSG 3 is
lower than the pressure in the heat exchanger 20, so portion of the liquid
water is flashed and transfer
phase to steam. The spherical balls also absorb heat in the heat exchanger 20
and release this heat to the
slurry as the pressure drop and the liquid water flashed in DCSG 3 for the
water phase change. The
rotating vessel 3 includes the spherical elements 1 and rotating lifting
scopes 10 to facilitate the mixture
of the slurry with the steam 8 and to enhanced the internal direct heat
exchange within the rotating
enclosure. Additional superheated steam 8 is added to the rotated vessel to
transfer the water phase
change through direct contact heat exchange. The solids introduced to the
system with the low quality
fluid 17 and the circulating balls 1 are discharged from the rotating
enclosure 7 to a separator to separate
the circulating balls from the solid waste 16. Any commercial available
separation method can be used. In
the example a rotating screen 12 is described. Any other method like vibrating
screen, cyclones or any
other commercially available method can be used as well. The recycled balls 14
are added to the low
quality water like FT or MFT. The produced steam 5 can be used for various
uses in the oilsands
extraction process. For a system that consume FT or MFT 17 and produces hat
extraction water, the
pressure in the rotating enclosure can be low, only slightly high them
atmospheric pressure and the
produced steam 5 can be directly mixed with the cold extraction water to
produce hot extraction

16


CA 02770651 2012-02-29

water.FIGURE 2D shows a schematic of a vertical SD-DCSG. It is similar to
Figure 2A with the
following changes: Vessel 11 includes a liquid water 1 bath at its bottom. The
water is maintained at a
saturated temperature. Saturated water is recycled and dispersed 3 into the up-
flow flow of dry steam 9.
The dispersed water evaporates 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. A portion of the
saturated water 1 is dispersed
at the up-flow stream of dry steam. The water evaporates and is converted to a
lower temperature steam.
For small recycle rate 3 solids are carried 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. Large
amount of saturated liquid water 13 can be circulated and mixed with the up-
flow steam 9. This liquid
circulation will wash the solids with the down falling liquid water droplets
into the sump while generating
cleaner produced steam 8. The solids rich water 12 is removed in a liquid form
for disposal in a cavern or
disposal well or for further treatment. Heat can be recovered from the
disposal water prior for thied
disposal.
[107] 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 Tailings 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 7 evaporates and is
transferred into steam. The
remaining solids 12 are removed from the system. The solids 12 can be removed
in a solid or slurry form.
The solids discharge temperature is close to the produced steam temperature
and this can be used for
further drying by loosing water vapor to the air. If the solids are in dry
form, additional contaminated
water can be added while allowing the solids heat to evaporate additional
water to the air. The generated
steam 8 is at the same pressure as that of the drive steam 9 but at a lower
temperature because 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 than) the saturated
temperature of the steam at the pressure
inside the 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 a temperature of 70-90 C. 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 used for other processes as a water source for a High
Pressure steam boiler, as an
example. In case that Non-Condensed Gases (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
17


CA 02770651 2012-02-29

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).

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. FT or MFT 7 are
injected into a SD-DCDG. In Figure2F, a vertical fluid bed SD-DCSG is
schematically represented.
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 are mixed with the 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 are removed in a stable form 12 where they can be
economically disposed of
and can 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 (Non Condensed Gases) 17 are generated due to the presence 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 hydrocarbons 17
recovered from typical
oilsands tailings, even that 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 of the process
heat energy used to generate
the driving steam 9. One option is to use a standard boiler 18 designed to
generate steam from liquid
water feed 19 from a separate source. Another option is to use a 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 BFW quality. Treatment units 24 are commercially available.
Another option to generate the
driving steam 9 is to recycle a 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 to
generate the flow through the heater 18 and the SD-DCSG 11. The compression
can be done using a
steam ejector with high pressure additional steam or with the use of any
available low pressure
difference mechanical compressor. The recycled produced steam 21- possibly
after additional cleaning,
like wet scrubbing, to remove contaminates like silica- is indirectly heated
by combustion heater 18. It
is also possible to use and recycle the light hydrocarbons 17 like solvents
back in the froth separation
process instead of burning it as a fuel.

18


CA 02770651 2012-02-29

[108] 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 is 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 commercially available unit to create the recycle
flow 36 can be used as well.
The produced steam, after its pressure is slightly increased to generate the
recycle flow 36, and possibly
after the 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. The heat
exchanger 38 is not a boiler as the feed is in gas phase (steam). There are
several commercial options and
designs to supply the heat 37 to the process. The produced steam 31 or just
the recycled produced steam
32 can be cleaned of solids carried with the steam gas by an additional
commercially available system
(not shown). The system can include solids 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 shown on
Figure 3. Typically, the re-
heater 40 supplies the heat to operate the second stage (low pressure) steam
turbine. Accordingly, the feed
to the re-heater is saturated or close to saturated medium-low steam. As such,
this minimizes the re-
heater design conversion changes to heat the generated steam 31 for generating
the superheated steam 36.
If an existing steam power plant is used, the supercritical high-pressure
steam can be used to drive a high
pressure steam turbine, while the remaining heat can be used through the re-
heater to provide the heat 37
to drive the steam generation facility. The advantages of this configuration:
a high pressure steam turbine
has smaller dimensions and Total Installed Cost (TIC) compared to medium / low
pressure steam turbine
per energy unit output.
[109] 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 a
rotating pressurized enclosure 30. The rotating SD-DCSG enclosure consumes
liquid water 34, possibly
19


CA 02770651 2012-02-29

with solid and organic contaminations, and generates lower temperature steam
31 and solid waste 35 that
can be disposed of in a landfill and can support traffic. The rotating SD-DCSG
30 is described in Figure
2C.
[110] 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 dry 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
can be disposed of in a
landfill and can support traffic. The driving superheated steam is generated
by recycling a portion of the
produced steam 32. The recycled produced steam is compressed to overcome the
pressure loss and
generate the required flow. It is indirectly heated 38 and recycled back 36 to
the SD-DCDG 30.
[111] FIGURE 3C is an illustration of a SD-DCSG with a 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,is
injected into the enclosure. The enclosure is pressurized. The liquid water is
evaporated to generate
produced steam 33. The produced steam 33 is at a lower temperature as compared
to the superheated
driving steam; it is close to the saturated point due to the additional water
that was evaporated and
converted to steam. The solids that were introduced with the low quality
liquid water 34 are removed in a
stable form where they can be disposed of in a land fill and can support
traffic. To increase the direct
contact heat transfer within the enclosure 30, moving internals are used. The
internals can be any
commercially available design that is used to mobilize 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 mobilizes the solids and
drives them to the discharge
location where they are discharged from the pressurized enclosure.
[112] FIGURE 3D is an illustration of a modification of Figures 3C and 3B for
a steam drive
Non-Direct contact steam generator where the heat is 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. The process includes generating or heating steam 36 through indirect heat
exchange (not shown).
The generated steam energy 36 is used to indirectly gasify liquid water 34
with solids and organic
contaminates, like fine tailings, so as to transfer said liquid water from a
liquid phase to a gas phase 33.
Solids 35 are removed 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 to usie 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


CA 02770651 2012-02-29

plant, are injected into the enclosure. The enclosure is pressurized. The
liquid water evaporates due to a
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 are removed in a stable form
35 where they can be
disposed of in a land fill and can support traffic. To increase the direct
contact heat transfer within the
enclosure 30 and to mobilize the solids and slurry, moving internals are used.
The internals can be any
commercially available design that is used to mobilize slurry and solids in a
cylindrical enclosure. The
rotating movement can agglomerate the solids into small spheres to increase
the solids stability and
minimize dust generation. A rotating screw 31 can be used. The rotating
movement 32 is provided
through a pressure sealed connection from outside the enclosure. The screw
mobilizes the solids and
drives them to the discharge location where they are discharged from the
pressurized enclosure. Any other
design (like double screws, lifting scoops, or chains) can be used as well.
Condensed water 36A from the
condensing driving steam 36 is recycled to the point where it can be re-heated
for generating additional
driving steam 36 or for any other use.
[113] 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 levels of suspended
and dissolved solids like fine tailings, produced water, evaporator brine,
brackish water, produced gas,
carbons, hydrocarbons or any available water feed possibly 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 and 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, mechanical energy is
supplied to the enclosure. One possible, simple way to supply the mechanical
energy is by a longitudinal
rotating element 9. There are several designs for such a rotating element that
can include spirals, scoops,
scrapers or any other commercially 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 into a longitude enclosure with an internal rotating element to introduce
mechanical energy into 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 a spiral in the opposite direction, to the driving steam 16 flow
and discharged from the
21


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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, which is fed into the second system 18 or 7.
[114] 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 a
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
commercially available
solids separation design. A commercially available gas-solid separation
package 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.
[115] 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-up. 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, such as tailings
pond water. The injected water 7 can include dissolved 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
is injected at section B located below the water injection 7. The dry steam is
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 which can prevent
build up of solids deposits on the enclosure wall. The solids rich
contaminates 4 that were introduced into
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 dispersed by a
nozzle 10 close to the enclosure wall in such a way that part of the steam
flow will be spread and then will
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
into 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 similar to the
pressure of the superheated
driving steam 5, except for 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.

22


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[116] 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 includes a fluid bed 4. This fluid bed includes liquid, solids
and slurry supplied with the feed
water 3. Additional free moving bodies, like sand, round metal particles, or
round ceramic particles can be
added to the fluid bed 4 to enhance the heat transfer between the up flowing
steam and the slurry from the
water feed 3 and to mobilized sticky slurry and solids. The fluid bed in
Section C can include additional
steam injectors (not shown) to mobilize 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. A mechanical means to create movement within the
fluid bed can be used as
well, possibly in intervals, in case the steam up flow from Section B is not
sufficient to prevent
solidifications 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, a 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 a commercially available demister and gas-solids separator to
remove water droplets or flying
solids carried-on with the generated steam flow.
[117] FIGURE 31 is a steam drive direct contact steam generator apparatus.
Superheated steam
7 is injected into 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 a 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, such as open
mine tailings pond water. The injected water 3 can include dissolved 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 continuous or interval
movement between its parts or
between the internal structure and 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 relative movement between the
upper bed structure 4 and the
23


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lower bed structure 6 and the enclosure wall. Any commercially available
design for 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
injecting it underground, like in SAGD or CSS, or to heat water in an open
mine extraction process.
[118] FIGURE 3J is a steam drive direct contact steam generator with an
internal wet scrubber
that generates additional wet solids free steam. Superheated steam 10 is
injected into Section A of the
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 increases 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 a moving or
vibrating bed. Solids can be
recovered from the fluid bed at Section A to maintain a constant solids level.
The up-flow generated
steam, possibly with solids particles, flows into 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 it 2 into the
up flowing steam, thereby scrubbing any solids remains and generating
additional steam. In Figure J, both
options are presented (the liquid bath is combined with the water sprayers 2)
however it is possible to use
only one of the presented options. If only the 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, ensuring any solids are scrubbed, from Section B that is supplied to
Section A and evaporated
there. The generated solids free saturated steam from Section B flows 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
requires steam.
[119] 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 Figures
2C, 2D and 2E can be used as well. The produced steam 9 flows 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 a saturated
temperature and pressure is
continually recycled and injected into the steam generator 2. Water feed,
possible with high levels of
contaminates, is fed into the system. Portion 14 of the produced steam 13 can
be used for any industrial
24


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use, such as for oil recovery 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 commercially available
filter package to remove contaminates like gas silica remains. Water and
chemicals 17 can be 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 then flows to steam heater. Depending 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 20 with high pressure steam feed to generate the recycle
flow 21. The steam flow 21 is
further heated in any commercially available heating system 23. Heat flow 22
increases the steam
temperature 24 to generate a dry, superheated steam flow that is injected back
into the direct contact
steam generator as the driving steam.
[120] FIGURE 3K1 illustration a SD-DCSG as described in Figure 3K with the use
of pre-
heater and spherical bodies circulation. Block A is an open mine oilsands
extraction facility. Fine
tailings or Mature fine tailings 17A are mixed with spherical bodies 15A and
pre-heated through
an heat exchanger 19A. The heated stream 2 is injected to a SD-DCSG 1 where it
is mixed with
superheated steam 24 in a fluidized bed 3. The solids introduced with the FT
or MFT are
discharged from the bottom of the system together with portion of the
spherical bodies 7 and
separated where the contamination solids 14A, mainly clay and sand that were
introduced with
the tailings 17A are disposed and the spherical bodies 15A are recycled. The
produced steam 9 is
splitted to steam flow 9A and 14. Steam flow 14 is used in the extraction
facility BLOCK A to
generate hot extraction water. Steam flow 9A is scrubbed with saturated
mixture of water, Soda
caustic and possibility other chemicals 11 to remove contaminates like silica.
The scrubber is
also an additional direct contact steam generation as additional saturated
steam is produced in
vessel 10. To replace the water converted into steam in vessel 10, additional
water 4 is added
from the oilsands extraction facility BLOCK A. To prevent contaminated build
up portion of the
high Ph water 8 is discharged and mixed with the extraction water. The high Ph
(due to the
caustic component) is an advantage as the extraction process normally uses
soda caustic with the
extraction water. The portion of the clean steam is used to generate
superheated steam 24. It is
slightly compressed 20 to create the circulation (possibly with steam ejector -
not shown) and
heated in a non-direct heat exchanger / heater 23. The superheated steam 24 is
used in the SD-
DCSG as the driving steam in an up-flow fluid bed steam generation process.
[121] 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 I includes the system described in FIGURE 3 where
BLOCK 32 can


CA 02770651 2012-02-29

include solids removal as a 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 with corrosion or solids build ups in
the high temperature heat
exchanger. One way to remove the solid contaminates is by the use of 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 possibly 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 then used as a means to improve the heat transfer. Low quality
water from the oil-water
separation process, fine tailing water from tailings ponds 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 and other type of carry-on contaminates. One option
is to use caustic chemicals
like NaOH that can efficiently remove silica contaminates and protect the heat
exchanger 38 from
contaminates built-ups and corrosion. 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 so it is
constant. The blow down 43 from the condensate 41 used to remove contaminates
in vessel 40 can be
directly added to the process water used for tar separation open mine
extraction process water.
Contaminates levels in the scrubbing water 43 are acceptable to the process
water and the caustic is
reused as part from the hot extraction water that normally includes caustic.
Additional low quality water
47A can be added to the SD-DCSG without pre-heating so as to prevent excessive
cooling of the
produced steam 33 and to prevent the generation of excessive condensate. The
generated steam, after
going through the wet scrubber, is a clean and saturated ("wet") steam. A
portion of the clean steam 45 is
directed through heat exchanger 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 commercial unit that can
be driven by mechanical
energy or can be a jet energy driven compression unit (like steam ejector).
The produced clean saturated
steam 46 can be injected into an underground reservoir, like SAGD, for oil
recovery, and it can also be
used for heating process water for tar separation or for any other process
that consumes steam.
[122] 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 of solids in commercial unit 32, previously
described. Low quality
26


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water 34, like MFT, produced water or water from any other available source,
can be injected into 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. Boiler
Feed Water (BFW) 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 and 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 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, which includes a wet scrubber. The wet scrubber 50 can contain
chemicals like ammonia,
soda caustic or any other chemical additive to remove contaminates. The exact
chemicals and their
concentration will be determined based on the particular contaminates of the
low quality water that is
used. Additional wet steam is generated in the wet scrubber 50. 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, is removed from vessel
50 and recycled back to the SD-DCSG 30 together with the feed water 34. When
the system is used to
generate hot extraction water, the liquid water 51 with the scrubbing
chemicals, like soda caustic, can be
added directly to the extraction water. 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 heavy oil or can be used for any other use.
[123] 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 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 heating 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 or added to the extraction hot water, if the
system is used in an open
mine oilsands plant. The additional condensate- clean BFW quality water 49- is
used in BLOCK 4 for
generating steam. The condensate is hot- it is at the water or steam saturated
temperature at the particle
27


CA 02770651 2012-02-29

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 of a
combined cycle. At least part of the produced dry superheated steam 36 is used
to operate the SD-DCSG
30.
[124] 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 addition of 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 or
for any other use.
[125] FIGURE 5C is a schematic diagram of a 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 those in the previous Figure 5B.
[126] 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 I and oxidizer 2 are combusted in the boiler
3. The combustion heat is
recovered through a 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 required
quality of the supplied water is
according to 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, is injected into an underground formation through
an injection well 16 for
28


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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 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.
[127] FIGURE 6A is a schematic flow diagram of the integration between SD-DCSG
and
DCSG that uses the combustion gas generated by the 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 I 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, for
example, 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
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.
[128] FIGURE 6A1 shows a schematic diagram of the present invention as
described in
FIGURE 6 with a produced water pre-heater. Boiler 3 produces steam 18,
preferably high pressure
saturate steam from treated boiler feed quality water 6. This steam is
produced using heat exchanger 5A.
The produced steam is used for pre-heat the produced water 7 to generate
heated produced water 7A.
Treated Boiler Feed quality water 6 from a prior art water treatment facility
within BLOCK 2 is supplied
29


CA 02770651 2012-02-29

to heat exchanger 5 within the boiler. The produced superheated steam is used
in a non-direct heat
exchanger 17 for pre-heating the low quality water feed 7. The heated liquid
low quality feed 7A injected
into the SD-DCSG 11. The condensate 19 after heating low quality stream 7
returns to the boiler at
BLOCK 1 for generating super heat stream 9 through heat exchanger 5A within
the boiler. The generated
superheated steam 9 is injected to the SD-DCSG 11 as the driving steam for
transferring the phase of the
low quality water 7A from liquid to gas for generating injection steam 8. It
is also possible to use the SD-
DCSG with an open mine oilsands extraction facility where the low quality
water 7 will be fine tailings
from the extraction facility and the generated steam 8 will be used to heat
the extraction water.
[129] FIGURE 6A2 shows a schematic diagram of the present invention as
described in
FIGURE 6A1 with a separate closed loop for the produced water pre-heater. The
boiler 3 produced steam
18 in a closed loop, preferably high pressure saturate steam from treated ASME
Boiler Feed quality water
6. This steam is produced using first heat exchanger 5A working in a closed
loop to pre-heat the produced
water 7 to generate heated produced water 7A. By separating the pre-heat
system from the superheated
system it is possible to use higher pressure saturated steam for pre-heating
the low quality water to
achieve higher pre-heating temperature 7A and eliminate the need to treat the
closed loop water. It is also
possible to heat the low quality water directly with the combustion gas
generated by boiler 3 at BLOCK 1
before injecting the pre-heated low quality water 7 to the SD-DCSD 11 (not
shown). The low quality
water 7 can be produced water from underground steam injection systems or
tailings water from an open
mine facility system (not shown). The superheated driving steam 9 pressure is
dictated by the steam
injection pressure. It cab include cleaning units as described in FIGURE 2B,
4, 5, 5A etc'. For an open
mine extraction facility a lower pressure steam, as lower as I bar can be used
(not shown).
[130] FIGURE 6A3 is a diagram of one embodiment of the present invention
described in
FIGURE 6A1 with a solid fuel boiler. Boiler 3 produce steams 18, preferably
high pressure saturate steam
from treated Boiler Feed quality water 6. This steam is produced using heat
exchanger 5 within the boiler.
The produced steam is used for pre-heating the low quality water (like
produced water, brine from
evaporation facility, sludge from softening facility, tailings from open mine
extraction facility or mature
fine tailings from tailing ponds). BLOCK 1 describes a solid fuel burner like
coal or petcoke. This type of
solid fuel burner is much more complicate and require higher investment to
construct. It is justified from
the economic perspective only when there will be a significant difference
between the price availability of
natural gas compared to the cost of solid fuel. At the current natural gas low
prices the boiler in BLOCK 1
will be simplifies to use natural gas as fuel source. This will reduce the
boiler TIC cost. Solid fuel like
coal or petcoke 1 is mixed with hot air 2A in a pulverizer 24. The fuel-air
mix is combusted in a burner 25
inside boiler 3. Solid waste like ash is removed from the bottom of the boiler
22. Additional pre-heat air
2B is fed to the boiler to support the combustion inside the boiler 3. The
boiler includes a steam drum 26.


CA 02770651 2012-02-29

To remove accumulation solids there is a blow-down from the steam drum. High
pressure steam 19 is
generated in heat exchanger 5. The steam is used to preheat a feed of low
quality water 7 in heat
exchanger 21 to generate heated low quality water 7A. From the heat exchanger
21 the heating steam 19A
flows to re-heater heat exchanger within the boiler. Any condensed water 21 is
separated and added to the
liquid water feed 6. The pressure at the low quality feed water heater 21 is
higher than the re-heater heat
exchanger 5A and the SD-DCSG 11. Air 2 is slightly compressed with the use of
fan 32 and heated with
the discharged combustion gases 28 in air preheater 23. The preheat air 2B is
supplied to the boiler. The
combustion energy is used to generate high pressure saturated steam in heat
exchanger 5 that is connected
to a steam drum / header 26. Blow down water 30 can be removed from the drum.
It is possible to use
other designs that include separated steam drum and a mud drum with the first
heat exchanger 5 in-
between (not shown). The high pressure steam, at a pressure of more than
20bar, and most preferably
more than 100bar is used to pre heat the contaminate water feed 7 in heat
exchanger 21 to generate heated
water feed and by that increase the amount of water that will be converted to
steam in the SD-DCSG 11
for a given amount of superheated driving steam 7A. The HP steam after heating
the low quality water,
like fine tailing or produced water is reheated in a heat exchanger 5A. The
pressure of the steam 20
introduced into 5A can be reduced to any lower pressure as long it is higher
than the pressure in the SD-
DCSG 11. Any condensate 27 is removed from the steam 19A and can be recycled
to the BFW (Boiler
Feed Water) 6. The BFW flow through economizer heat exchanger 5B and
additional heat exchanger 5 to
generate high pressure saturated steam flow 31 at steam drum 26. One option is
to further heat the HP
steam 31 before using it to pre-heat the low quality water flow at heat
exchanger 21. It is also possible to
use the produced saturated steam 31 without further heating in heat exchanger
21. The super heated steam
9 flows to a SD-DCSG 11 where it is mixed with the heated contaminated water
7A. There are few
designs that can be used to mix the contaminated water with superheated steam
and remove the solids. In
this figure a fluid bed DCSG is schematically presented. The solids
contaminates 12 are removed from
the bottom. The DCSG includes a separator like a cyclone 11A or demister
packing (not shown) to
remove carry-on solids and liquid droplets from the produced steam 8. The
produced steam 8 is used for
steam injection or for generating hot process water. Any other SD-DCSG that
was described in other
figures can be used. The produced steam 8 can be used for any steam use. This
includes steam injection
into an underground formation or generating hot process water for oil
extraction as described in the other
figures.
[131] FIGURE 6B described a direct contact steam generator with rotating
internals, dry solids
separation, 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
31


CA 02770651 2012-02-29

system in a dry or slurry form. The produced steam is treated in a
commercially available gas treatment
unit in Block B. An inlet demister, to remove carried-on liquid droplets, can
be incorporated in Block B.
Any commercially available unit to remove solids and contaminates can be used,
such as cyclone solids
removal system schematically described in B 1, a high temperature filter B2,
an electrostatic precipitator
B3 or a combination of these with any other commercially available design. The
solids are 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 is recycled and
dispersed into the flowing
steam. A portion of the liquid water evaporates. The water droplets remove
contaminates. Chemicals like
anti-foaming, flocculants, Ph control and other commercially 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 into steam and to replace the
recycled water with
contaminates, back to the feed water 13. The scrubbed solids free generated
steam 8 is supplied from the
system for other usages.
[132] 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 a 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 further separated
into the produced bitumen, usually diluted with light hydrocarbons to enhance
the separation process and
to reduce the viscosity which allows the flow of the bitumen in the
transportation lines. In BLOCK B, the
produced water that remained with the flow 4 is de-oiled and used, usually
with make-up water from
water wells, for generating super-heated steam 6. The water rich flow 5, at a
high temperature that is close
to the 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 required to generate hydrocarbons that are injected with the
injection steam 2 into the
underground formation 11. Additional solvents can be added to the injection
steam 2- it is a common
practice to add solvents to the generated steam for injection. It is known
that hydrocarbons that are mixed
with the steam can improve the oil recovery. The SD-DCSG 7 includes rotating
internals to enhance the
mixture between the two phases and to mobilize the generated slurry and
solids. The solids 8 are removed
from the system for landfill disposal 13 or for any other use. The heat energy
within flow 5 from separator
3 increases the quantity of 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
32


CA 02770651 2012-02-29

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, or the
rotating or fluid bed units as
described in drawings 2C, 2D and 3C-3J can be used as well.
[133] FIGURE 6D includes a 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 a few commercial designs 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 a 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 increases the quantity of 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 are
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 of flow 18,
flow 12, is recycled back 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 commercially available
cleaning technologies. The recycled produced steam is compressed by a
mechanical compressor, steam
ejector or any other available unit 14 and then indirectly heated by heat flow
15 to generate a super heated
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.
[134] FIGURE 6E is a schematic view of the SD-DCSG with similarities to Figure
6D and with
externally 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
a 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 a commercially available oil and
water processing plant at
33


CA 02770651 2012-02-29

BLOCK B. There are commercially available technologies and designs for such
plants- 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 in 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 is 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 industry or in
any other industry that required large quantities of steam. Additional
solvents can be added to the
injection steam 2- it is a common practice to add solvents to the generated
steam for injection. The other
part from flow 18, flow 12, is recycled to be re-heated and used 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 High Pressure (HP) 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-oiling and
possibly de-mineralization before
being used in a commercially 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 a water well 25 or can be from 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.
[135] FIGURE 6F describes another embodiment of the present invention for
generating steam
for oil extraction with the use of a 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. 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 was already removed, is fed into
separator 35. Chemicals,
sometimes with solvents like light hydrocarbons, can be added to the produced
liquid 39 to support the
34


CA 02770651 2012-02-29

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
within the heavy oil
industry. The gas separator reactor 33 and the water-oil separator reactor 35
are commercially available
units. Any additional configuration to enhance the gas-water-oil separation
can be used as well. The
produced 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 a commercially
available water treatment facility, like evaporators, to generate boiler feed
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, such as water wells. Usually the make-up
water does 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, is mixed
with superheated steam 6. Due to the contaminates within the produced water
feed 7, a rotating internal 2
is used to enhance the mixture and remove build-ups within enclosure 1. It is
also possible to use any
other system to mix the superheated steam and the produced water like fluid
bed as described in Figure
2A,2D, 3G, 3H, 31,3J or rotating enclosure as describes in figure 2C, 3A, 3B,
3C, 3D, 3E or any other
system structure. Due to the driving steam's 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 a portion of the water into steam
and dispose of the remaining
water with the contaminated solids 12 in a disposal well 13 or send it for
further treatment in a separate
facility. Heat can be recovered from the disposal liquid flow 12 through a
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 a ZLD facility is
preferred, most of the water 7 can
be converted into steam, generating solids or a stable slurry 15 for landfill
disposal 16 or for further
treatment. The produced steam flow 20 is used for injection for thermal oil
recovery through an injection
well. A portion 21 of the produced steam 20 is used to generate the driving
superheated steams 6. The
clean BFW 28 is used for generating steam through a commercial boiler or OTSG
that includes a heat


CA 02770651 2012-02-29

exchanger 26 to generate High Pressure steam 24. Any type of commercially
available boiler and steam
separation vessel can be used. The produced HP steam 24 pressure energy 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 circulation of the produced steam 21 is done through steam ejector
23 that uses 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 in the other examples, the
produced steam 21 can be further
treated in a separate unit to remove contaminates, like silica, from the
produced steam flow that can affect
the super heater heat exchanger's 27 performance and create deposits. There
are a few technologies that
can be used. One option is to use a liquid scrubber with saturated liquid
water, possibly with chemicals,
like magnesium oxide, caustic soda or other chemical additives, 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 solutions available 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 levels
of contaminates, as required
by ASME specifications for boiler feed water. There is a lot of knowledge and
commercially available
packages to generate the BFW 40 used for generating the high pressure steam
24. In the current sketch,
the boiler integrates 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 operating
the ejector and using the super-heated steam 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 a 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 driving
steam with any commercially available heat exchanger design. The heater can be
integrated into the boiler
or a separate unit with any available heater design. The steam generation unit
can be located on the well
pads or in close proximity to the well pads. This arrangement will minimize
the heat losses and allow the
use of the produced water heat. The high pressure steam 24 required to operate
the ejector can also be
produced remotely in BLOCK 1, whereas on the pad there will only be steam
heater 27.
[136] FIGURE 6G shows a schematic view of inventive natural gas boiler with
super heater
for generating superheated steam and SD-DCSG for generating steam for oil
extraction. The system that
includes the steam injection and production well, the separator and the
Central Process Facility BLOCK
A is described in Figure 6F. Block A includes a water treatment plant to
generate boiler feed water 40.
The system includes a gas or liquid boiler 25 for producing superheated steam
6 from treated BFW 40.
The BFW is generated from the produced water mixed with the bitumen 41 and
possibly from other
sources of water like water wells. (not shown) There are few commercial
available technologies to
generate the produced water 40, most of the technologies are based on
evaporation for the generation of
36


CA 02770651 2012-02-29

distilled BFW. The boiler includes a steam drum 26, that can be an external
vessel as well connected to an
heat transfer section. Blow down water 5 removed from the bottom header. The
boiling section of the
boiler 25, where the water are changing phase from liquid to gas is located
close to the burner, where the
most direct radiation from the combustion exist. This location (close to the
burner) allows consuming
most of the energy to transfer the phase of the water from liquid to gas,
which is the major energy
consumption within the boiler while maintaining the pipe of the heat transfer
at a controllable temperature
due to the two phase medium within the pipe. The generated steam from the
steam boiler 4 is saturated
and flows to a super heater section 27 adjusted to the boiling section. It is
also possible to use the
saturated steam for pre-heating the low quality water 7 as described in figure
6A3. The heat transfer
within the super heater section is with the combustion gases leaving the
boiling section 26. The radiation
in this area is less then at the boiling area within the boiler. Superheated
"dry" steam 6 is generated as the
product from the boiler to operate the SD-DCSG 1. The combustion gases leaving
the superheater section
27 still includes large amount of heat as normally their temperature would be
higher than the saturated
steam 4. The heat cam be used for pre-heating the produced water 7. Heat
exchanger 28, located after the
pre-heater can used to remove heat from the combustion gas for pre-heating the
produced water in heat
exchanger 9. The need in heat exchanger 28 that is used as a pre-heater for
the low quality water 7 is
depend on the specific system characteristics and mainly on the composition
and the temperature of the
produced water. Where the produced water temperature (or fine tailings
temperature if the system is used
in an open mine (not shown)) is low compared to the saturated steam 4
temperature there will be a
justification to add a produced (or tailing) water pre-heater. If pre-heater
28 is used the temperature of the
combustion gases leaving the preheater will normally be higher than the
produced water 7 temperature.
The pre-heater can recycle clean recycled water as heat transfer medium or
used produced saturated steam
4 (not shown). The remaining heat energy within the combustion gas leaving the
low quality water 7 pre-
hater 28 (or the super heater 27, if pre-heater is not used) is used within
economizer heat exchanger 29
where the BFW 40 are pre-heated before introducing into the boiling heat
exchanger. The boiling section
can be a natural circulation with steam drum and "mud" bottom header or forced
circulation (not shown).
The super heated dry steam 6 is mixed with the lower quality produced water 7
or heated produced water
8, if pre-heater is used. The mixture is done in a fluid bed enclosure 1.
Solids are removed from the
bottom of enclosure 1 in a dry form or, if liquid disposal is preferable, in a
liquid form 12. For liquid
disposal 12 circulation flow 13 can be used to circulate liquid water from the
liquid sump to the up
flowing superheated steam flow 6 (as described in Figure 2D and others). Any
other type of SD-DCSG 1
like the different types described in the other figures can be used as well.

37


CA 02770651 2012-02-29

[137] FIGURE 7 is a schematic view of an integrated facility of the present
invention with a
commercially available steam generation facility and for FOR for heavy oil
production. The steam for
FOR is generated using a lime softener based water treatment plant and an OTSG
steam generation
facility. This type of configuration is the most common in FOR facilities in
Alberta. It recovers bitumen
from deep oil sand formations using SAGD, or CSS, etc. Produced emulsion 3
from the production well
54, is separated inside the separator facility into bitumen 4 and water 5.
There are many methods for
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 300 C.
In a standard SAGD system,
the steam is separated in a separator to generate 100% steam 29 (for EOR) and
blow-down water. The
blow down water can be used as a heat source and can also be used to generate
low pressure steam. The
steam, 29 is delivered to the 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
the Ion-Exchange system 20. The reject streams are collected 33 and injected
directly 33A into Steam
SD-DCSG 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 120 C and 300 C. The
pressure can vary
38


CA 02770651 2012-02-29

between Ibar and 50bar. 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 in order 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 is 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
generated 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.
[138] FIGURE 8 is a schematic of the invention with an open mine oilsands
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 J.
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 tailings is the
recycled water layer 58. The
tailing concentration increases with depth. Close to the bottom of the tailing
layer are the MFT. (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
39


CA 02770651 2012-02-29

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 oilsands 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 open mine
oilsands facilities.
[139] FIGURE 9 is a schematic view of the invention with an open mine oilsands
extraction
facility and a prior art commercially available pressurized fluid bed boiler
that uses combustion coal for a
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
pumpable slurry 59. The water
62 is recycled water with a high level of contaminates 38, as discharged from
the SD-DCSG 28. Some
portion of 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 is
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 an average pressure of 103kpa and up to 1.5Mpa, and temperatures
of 200 C-900 C. The


CA 02770651 2012-02-29

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 removes solids and possibly contaminated gases 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 quality water 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 dissolved CO2
which increases the bitumen fluidity.
[140] 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
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 into a DCSG. It
includes reduced capacity internal heat exchangers to recover less combustion
heat. The reduction in the
heat exchanger's 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 solids rich water 52
thereby 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 steam 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 16-19 May, 1999 and US RE37,300 E issued to Nagato et al on July
31, 2001). Any other
41


CA 02770651 2012-02-29

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 in the 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.
[141] 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 stack
3. The generated steam is supplied to SD-DCSG 11 in BLOCK 4 which 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, in order to
react with the S02. 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 to generate BFW
that is added to the
distillate BFW 29 and then supplied to the steam generation facility. The NCG
(Non-Condensation Gas)
40 is released to the atmosphere or used for further recovery, like C02
extraction. The heat recovered in
heat exchanger 28 is used to generate steam to operate the MED 30 (a
commercially available package).
42


CA 02770651 2012-02-29

The water 1 fed to the MED is de-oiled produced water, possibly with make-up
underground brackish
water. The MED 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 ranging from
0.2bar to 12bar. 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.
[142] 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 the SD-
DCSG in BLOCK 3. Discharged brine from the commercial MED facility in BLOCK 2
is also injected
into the SD-DCSG 15 and converted into 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.
[143] FIGURE 11B is a schematic diagram of the present invention that includes
a steam drive
DCSG with a direct heated Multi Stage Flash (MSF) 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
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. A 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 C02. Steam 9 injected into a pressurized DCSG 15 at an elevated
pressure. The DCSG
43


CA 02770651 2012-02-29

design can be a horizontal sloped rotating reactor, however any other reactor
that can generate a stream of
steam 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 into
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 acts like 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 the steam on tubes that carry the feed water through the vessel.
The heated water then
flows to the first stage. In the method described in Figure 11 B, 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.
A non-direct heat exchanger / condenser 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 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
saturated 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. There can be up
to 25 stages. A commercial
MSF typically operates in a temperature range of 90-110 C. 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
that separates the produced bitumen 8, possibly with diluent that improves
separation from the water
and decreases 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,
which 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.

44


CA 02770651 2012-02-29

[144] 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 4 includes the SD-DCSG which generates the injection steam.
BLOCK 5 includes a water-oil separation facility with the option of oily water
discharge for
recycling into the SD-DCSG.
BLOCK 6 includes the DCSG.
BLOCK 7 includes a syngas treatment plant where part of the syngas can be used
for hydrogen
production etc.
[145] Carbon fuel 5 is injected with oxygen rich 6 gas to a pressurized
gasifier 7. The gasifier
shown is a typical Texaco (GE) (TM) 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 also
generate saturated steam from the heat in gas flow 18. 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, such as the MSF or MED. 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


CA 02770651 2012-02-29

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 in 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 in 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 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.
[146] 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 IA 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 70 C-90 C, 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 Tailings 5 which, after a
time, is transferred to a stable
Mature Fine Tailings. Energy 1 is 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 to support traffic. The heat in the discharged
solids 4 can be used to
removed additional water in the form of vapor to the air while cooling and
drying the solids flow 4. 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
Figures 3, 3A or 3B (not shown). The produced steam 21 is mixed with cold
process water 8 from
BLOCK 1 A in a direct contact heat exchanger 7. The produced steam is directly
heated and condensed
into the liquid water 8 to generate hot process water 9 that is then supplied
back to operate the Open Mine
Oilsands plant IA. The amount of NCG 2 is minimal. Some NCG can be generated
from the organic
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 100 C to 400 C.
[147] FIGURE 13A is a schematic view of the process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Figure 13A is similar to Figure 13
46


CA 02770651 2012-02-29

with the notable 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 70 C-90 C, and
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, are transferred to a stable Mature Fine Tailings (MFT).
Energy 1 is injected into
reactor 3. The energy is in the form of steam gas which is injected around
enclosure 3 where the heat is
transferred to the reactor and to the MFT through the enclosure wall. The
driving hot steam gas is
condensed and recovered as a liquid condensate IA. 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 which can
support traffic. Steam I 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 produced
steam 21 is mixed with
cold process water 8 from BLOCK IA in a direct contact heat exchanger 7. The
produced steam is
directly heated and condensed into the liquid water 8 to generate hot process
water 9 that is supplied back
to operate the Open Mine Oilsands plant IA. The amount of Non Condensable
Gases (NCG) 2 is
minimal. Some NCG can be generated from the organic 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
100 C to 400 C.
[148] FIGURE 13B is a schematic view of the process for the generation of hot
water for
oilsands mining extraction facilities, with Fine Tailing water recycling.
Figure 13B is 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 mobilize
the high concentration slurry
and solids to the solid discharge 4, where stable material that can support
traffic is discharged from the
system. The produced steam 6 is further cleaned to remove solids in
commercially available solids
separation unit 20 like a cyclone, electrostatic filter or any other
commercially available system. The
generated steam 21 is mixed with cold process water 8 supplied from an open
mine extraction plant in a
direct contact heat exchanger 7. The produced steam is directly heated and
condensed into the liquid
water 8 to generate hot process water 9 that is supplied back to operate the
extraction Open Mine Oilsands
plant.
[149] FIGURE 14 is one illustration of the present invention for the
generation of pre-heated
water that can be used for steam generation or in a 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
47


CA 02770651 2012-02-29

steam, is introduced into 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 into
steam, leaving only 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 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) is
condensed into liquid water 10 in
a non-direct condenser 7. There are many commercially available standard
designs 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 volumes of NCG 2
can be treated or
combusted as a heat source (not shown). The condensed liquid water 10 can be
used as 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.
[150] 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 a non-direct heat exchange
and syngas can be used for the production of hydrogen for upgrading the
produced crude in prior-art
technologies or can be used as a fuel source. The MFT recovery is done with
the steam which was
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 59. The produced syngas 60 is recovered and further treated. This
treatment can include the
removal of the H2S (like in an amine plant). Treatment 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 gas-solid 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 11 and used as
hot process extraction water. In case NCG 17 is generated, it can be further
treated or combusted 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 done using a
centrifuge or 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
48


CA 02770651 2012-02-29

flow is fed into the DCSG 1 or recycled and used as 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.
[151] 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
tailings pond. A typical mine
and extraction facility is briefly described in block diagram I (See "Past,
Present and Future Tailings,
Tailing Experience at Albian Sands Energy" presentation by J. 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 via truck 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 a 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 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 the
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 concentration fine tailing stream 61 flows to the
DCSG facility 50. Steam
energy 47 is used in the DCSG to convert the fine tailings 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 an OTSG, or produced
by a COGEN, using the elevated temperature in a gas turbine tail (not shown).
The boiler consumes fuel
49


CA 02770651 2012-02-29

gas 38 and air 39 while generating steam 14. A portion 47 of the generated
steam 14 can be injected into
the DCSG 50. The temperature of the DCSG produced steam can vary from 100 C to
400 C as it includes
the water from the MFT. Steam 47 can be also generated by heating a portion of
the produced 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
evaporate the FT are condensed and added to the down-flowing extraction water
process 57. The presence
of small amounts of remaining solids in the hot process water is 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 70 C and 95 C, typically in the 80 C-90 C
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 can be
used to 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 in 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 to
generate trafficable solid material without relying on weather conditions to
dry excess water.
[152] 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
designed in such a way that the sand tailings are used to build the
containment areas for the fine tailings.
The tailings are generated in the 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


CA 02770651 2012-02-29

Treatment Tailings, where the tailings are discarded using the solvent
recovery process; the Froth
Treatment Tailings are 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 J. 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 are pumped from the
lower section of the tailing pond and are 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 turn into gas and solids as the water is converted into 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 and can be
used to support traffic. The
produced steam 14, of which 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 is a
simple way to deal with tailingsas 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 produced
steam 47, as described in
Figures 3, 3A and 3B.
[153] 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 by 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. Any other type of
51


CA 02770651 2012-02-29

DCSG can be used as well. Concentrated MFT 2 is injected into the DCSG 1 as
well. The MFT is
converted into 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 the 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
described is commercially
available and was tested successfully in two field pilots (See "The Past,
Present and Future of Tailings at
Syncrude" presentation by A. 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 a thick slurry ("cake") that contains more
than 60% solids. The solid lean
flow is used directly or is recycled back to a settling basin (not shown) and
is eventually used as process
water 35. The solid concentration is not dry enough to be disposed of
efficiently and cannot be used to
support traffic. This can be solved by mixing it with a "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. The heat within the solids 8 also remove water
from slurry 30 in a vapor
form to the atmosphere while reducing the temperature of the discharged solids
for disposal. In this
particular figure, the mixing 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 use 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.
[154] 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
gases are possibly
52


CA 02770651 2012-02-29

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 DCSG 15 at an elevated pressure. The DCSG design can include a
horizontal rotating
reactor, a fluidized bed reactor, 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 into steam and the solids are carried on with gas flow
13. The amount of water 14 is
controlled in order to verify that all the water is converted into 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 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
formations, 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 so that it can
reject contaminated water without environmental impact. It is sent to the DCSG
15, where most of the
organics are converted into hydrocarbon gas phase or are carbonic with the hot
steam gas flow. The
distilled water 19 produced by the distillation facility 11, possibly with the
condensed steam from 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 water are separated in commercially available plants
10 into water 9 and oil
product 8.
[155] FIGURE 20 is an illustration of one embodiment of the present invention.
It is similar to
Figure 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
53


CA 02770651 2012-02-29

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 into
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 Figure 19 above. To
minimize the amount of steam 9
used to drive the DCSG 15, it is possible to recycle a portion of the produced
saturated steam 22 as
described in Figures 3, 3A and 3B. This option is shown as the dotted line. A
portion of the produced
steam 22 is recycled to drive the process. This steam is compressed 42 to
allow the flow to be recycled
and to 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 part of a standard boiler design.
[156] FIGURE 21 is an illustration of a boiler, steam drive DCSG, solid
removal and
Mechanical Vapor Compression distillation facility for generating distilled
water in the boiler for steam
generation 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 concentrated brine 8 from the distillation facility, is injected
into 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 10 with solid
particles from the solid rich
water 8. The DCSG in BLOCK 22 can generate its own driving steam 7 by
recycling and heating a
portion of the saturated produced steam 12, as described in Fiures. 3, 3A and
3B (not shown). The amount
of water 8 is controlled to verify that all the water is converted into 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 solids 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 I 1 is mixed
with saturated water 22 in a direct contact wash vessel 15. The solid 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 into 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
54


CA 02770651 2012-02-29

use of the saturate water liquid scrubber 15. The produced saturated steam 23
is supplied to BLOCK 20,
which is a commercially available distillation unit that 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
into 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 (such as that 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 is 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 (which includes
a low pressure dryer), the
thermal efficiency of the system is lower than using a high pressurized system
with pressurized DCSG.
[157] The following are examples for heat and material balance simulations:
[158] 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 25 C with a constant flow
of 1000 kg/hour. The product 8 was saturated steam at 25bar. The graph below
shows the amount of drive
steam 9 required to transfer the liquid water 7 into the gas phase as a
function of the temperature of the
driving steam 9. When 300 C driving steam is used, there is a need for
12.9ton/hour of steam 9 to gasify
one ton/hour of liquid water 7. When 500 C driving steam is used, there is a
need for only 4.1 ton/hour of
steam 9 to gasify one ton/hour of liquid water 7. The following are the
results of the simulation:

Drive Steam 9 Drive Steam 9
Temperature(C ) Flow (kg/hr)
600.00 3059.20
550.00 3502.50
500.00 4091.50
450.00 4914.46


CA 02770651 2012-02-29

400.00 6159.21
350.00 8290.00
300.00 12990.00
250.00 34950.00
[159] Example 2: The graph in Figure 23 simulates the process as described in
Figure 2A. The
driving steam 9 temperature was constant at 450 C. The liquid water 7 was at
temperature of 25 C and
had a 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 the gas
phase as a function of the
pressure of the driving steam 9. When the system pressure was 2 bar, 3.87
tons/hour of driving steam was
needed to convert the water to saturated steam at temperature of 121 C. For a
50 bar system pressure,
5.14 tons/hour of driving steam was used to generate saturated steam at 256 C.
The simulation results are
summarized in the following table:

System Pressure Temperature of Saturated Driving Steam Flow
(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

[160] 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 100 C at lbar to around 312 C 100bar.
Thus, the amount of
superheated steam input at 450 C also increases from around 2300 kg/hr to 4055
kg/hr. The graph in
56


CA 02770651 2012-02-29

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
,C 25.00 50.00 120.61 120.61
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 2311.54 114.73 2896.81
Water 600.00 2311.54 114.20 2797.34
Solids 300.00 0.00 300.00 .14E-17
4aptha 100.00 0.00 0.53 99.47

[161] Example 4: The following table simulates the process as described in
Figure 3 for insitue
oilsands thermal extraction facilities, like SAGD, for two different
pressures. The water feed is hot
produced water at 200 C that includes solids and bitumen. The heat source Q
for the simulation was
12KW.
[162] For a system pressure of 400psi the total Inflow of water, solids and
bitumen of flow 34
was 23.4 kg. 77% of the steam 31 is recycled as the driving steam 32 while 23%
is discharged out of
system at 283 C steam and hydrocarbons.
[163] For a system pressure of 600psi, the total Inflow of water, solids, and
Bitumen of flow 34
was 22.5 kg. 80% of the steam 31 is recycled as the driving steam 32 while 20%
is discharged out of
system at 283 C steam and 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
57


CA 02770651 2012-02-29

Flow Number 34 35 31 32 36 33
T, C 200 282.88 282.88 282.62 485.97 282.62
Press., psig 600 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00
Enthalpy, kW -92.863 -4.78 -381.06 -305.04 -293.02 -76.26
Total Flow,
kg/hr 22.5 1.12 107.11 85.74 85.74 21.43
Water, kg/hr 20.925 0.00 104.86 83.93 83.93 20.98
Solids 1.125 1.12 0.00 0.00 0.00 0.00
Bitumen 0.450 0.000 2.255 1.805 1.805 0.451
[164] Example 5: The following process simulation described in Figure 30
simulates a 600psi
system pressure. 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 for insitue oilsands thermal extraction facilities like SAGD. The
graph shows that for a constant
heat flow, as the produced feed water temperature increases, the amount of
produced steam increases
accordingly. The heat source Q in the simulation was 12KW. The driving steam
36 temperature was 482
C. 80% of the steam 31 is recycled to the heater as the driving steam 36 while
20% is discharged out of
system at 283 C steam and hydrocarbons. The simulation shows that for feed
water at a temperature of 20
C, 15.1 kg of produced steam is generated. For a temperature of 100 C, 17.4kg
of produced steam is
produced and for a temperature of 220 C, 22.4kg of produced steam is produced.
[165] Example 6: The following table simulates the process as described in
Figure 4 for insitue
oilsands thermal extraction facilities like SAGD. The water feed is hot
produced water at 200 C that
includes solids and bitumen. The heat source Q for the simulation was 12KW and
the system pressure
was 600psi. The total Inflow of water, solids, and bitumen of flow 47 was 22.5
kg. 79% of the steam 31 is
recycled as the driving steam 36 while 21 % is discharged out of system at 294
C steam and hydrocarbons.
[166] In the simulation, 4.9kw were removed at the flash/condensation unit 42
and used to pre-
heat the 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
58


CA 02770651 2012-02-29

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

[167] Example 7: The following table is the simulation results for the process
described in
Figure 25. The water feed 1 is produced water from a SAGD separator and
includes solids and
hydrocarbons at a temperature of 200 C. The produced water 1 is mixed with
superheated steam 7 at
approximately 482 C. 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 a temperature of 285 C and pressure of 600psi
is recovered from the
system as the product for steam injection, or any other use. The remaining 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 that were introduced with the
produced water (like
magnesium based additives, soda caustic, and others). Water 9 is fed into the
scrubber 23 and the
scrubbed water 12 is continually recycled back to the stage of 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 a 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.

Flow Number 1 2 3 4 5 6
T, C 200 284.78 284.78 284.78 284.77 284.77
Press., psig 600 600 600 600 600 600
Vapor Fraction 0 1 0 1 1 1
Enthalpy, kW -74.29 -330.8 -3.82 -326.94 -255.03 -71.93
Total Flow,
kg/hr 18 92.53 0.9 91.63 71.47 20.16
Water, kg/hr 16.74 90.01 0 90.01 70.21 19.8
59


CA 02770651 2012-02-29

Solids 0.9 0.9 0.9 0 0 0
Hydrocarbons 0.36 1.618 0 1.618 1.262 0.356
Flow Number 7 8 9 10 12
T, C 478.12 253.81 20 254.13 253.81
Press., psig 600 600 600 601.46 600
Vapor Fraction 1 1 0 1 0
Enthalpy, kW -255.05 -267.08 -13.25 -267.04 -1.21
Total Flow,
kg/hr 72.92 72.93 3 72.92 1.55
Water, kg/hr 72.92 72.93 3 72.92 0.28
Solids 0 0 0 0 0
Hydrocarbons 0 0 0 6.99E-06 1.262

Another option to minimize the risk of build-ups in the injection piping is to
recover the produced steam 6
from flow 8 (indicated on Figure 25 as flow 6A). This option was simulated as
described in the table
below. In reality, flow 6A will be cleaner than flow 6, because the steam will
be scrubbed by saturated
liquid saturated water 9. The scrubbing water 9 can include chemical to remove
contaminates, like silica,
from the produced steam 4. The simulation shows that this option do not affect
the overall process
efficiency. The size of scrubbing vessel 23 will increase with the increased
flow.

Flow Number 1 2 3 4 5 6A
T, C 200 267.16 267.16 267.16 267.16 253.81
Press., psig 600 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0 0.99 0.00 1.00 1.00 1.00
Enthalpy, kW -75.7649 -340.01 -3.93 -336.03 -336.03 -76.38
Total Flow,
kg/hr 18.36 96.85 0.92 95.93 95.93 20.86
Water, kg/hr 17.07 92.08 0.00 92.08 92.08 20.86
Solids 0.92 0.92 0.92 0.00 0.00 0.00
Hydrocarbons 0.370 3.848 0.000 3.848 3.848 0.000
Flow Number 7 8 9 10 12
T, C 481.86 253.81 20.00 254.1276 253.81
Press., psig 600.00 600.00 600.00 601.4696 600.00
Vapor Fraction 1.00 1.00 0.00 1 0.00


CA 02770651 2012-02-29

Enthalpy, kW -251.25 -263.09 -15.46 -263.249 -12.00
Total Flow,
kg/hr 71.89 71.84 3.50 71.88519 6.73
Water, kg/hr 71.89 71.84 3.50 71.88519 2.88
Solids 0.00 0.00 0.00 0 0.00
Hydrocarbons 0.000 0.000 0.000 3.17E-06 3.848

[168] Example 8: The following table are the simulation results for the
process described in
Figure 26. The water feed 1 is produced water from a SAGD separator and
includes solids and
hydrocarbons at a high temperature of 200 C. (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
is added later). The feed 1 is mixed with superheated steam 7 at approximately
482 C. 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 (75%) at a
temperature of 271 C and pressure of 600psi is recovered from the system as
the product for steam
injection in CSS, SAGD or any other steam use. Another option that wasn't
simulated is to clean and
scrub all the produced steam 4 to generate a cleaner produced steam for
injection 6A. This option can be
used in case contaminates in the produced steam 4 can damage the injection
facility or block the
formation over time. The remaining 25% of the produced steam 5 is cleaned in a
wet scrubber with
saturated water, potentially with additional chemicals to remove contaminates.
Water 9 with a flow rate of
0.3kg/hour and temperature of 20 C is fed 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 a flow of 10kg/hour and temperature of 20 C. The
generated water 11 at a
temperature of 250 C is pumped to low overpressure to generate circulation and
compensate for the losses
and is then transferred into superheated steam by a 12kw heater 25 to simulate
a 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 a flow
of 16kg/hour is used as
the driving steam to drive the process.

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, 7.870 24.105 0.390 23.715 5.932 17.797
61


CA 02770651 2012-02-29
kg/hr
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 -44.16 -65.87 -1.04
Total Flow,
kg/hr 15.927 5.927 0.300 10.000 15.927 0.305
Water, k 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

To minimize the risk of build-ups in the downstream piping and equipment it is
possible to recover the
produced steam 6 from flow 8 (indicated on Figure 25 as flow 6A). The
following table are the simulation
results for the process described in Figure 26 with flow 6A as the produced
steam exported from the
system. The produced steam 6A is extracted from steam flow 8 after scrubbing
in vessel 23 with liquid
saturated water 9. Additional chemical can be added to the scrubbing water 9
to remove contaminates
with stream 4.

Flow No. 1 2 3 4 5 6A
T, C 200.00 253.81 253.81 253.81 253.81 253.81
Press., psig 600.00 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0.00 0.89 0.00 0.95 0.95 1.00
Enthalpy, kW -32.47 -104.51 -1.67 -102.07 -102.07 -71.18
Total Flow,
kg/hr 7.870 28.770 0.390 28.380 28.380 19.436
Water, kg/hr 7.320 27.686 0.000 27.686 27.686 19.436
Solids 0.390 0.390 0.390 0.000 0.000 0.000
Hydrocarbons 0.160 0.695 0.000 0.695 0.695 0.000
Flow No. 7 8 9 10 11 12
T, C 482.16 253.81 20.00 20.00 239.99 253.81
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 -64.08 -23.73 -2.65 52.3303 -76.06 -9.81
Total Flow,
kg/hr 18.335 6.479 0.600 11.850 18.330 3.065
62


CA 02770651 2012-02-29

Water, kg/hr 18.335 6.479 0.600 11.850 18.330 2.370
Solids 0.000 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.000 0.695

[169] Example 9: The following table are the simulation results for the
process described in
Figure 27. The simulation is similar to Example 8 with a change to the
production of the boiler feed water
where instead of using clean Boiler Feed water to condense the generated steam
for generating the
superheated steam generator feed water, heat is recovered to condense the
steam to BFW and is
introduced back to the system to heat the feed water. By this arrangement, the
need for 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 a
temperature of 282 C and pressure of
600psi is recovered from the system as the product for steam injection or any
other use. The remaining
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 a flow of 4.lkg/hour and
temperature of 20 C is fed 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
returned 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 a temperature of 254 C, is pumped to low
overpressure to generate circulation
and compensate for the losses and is then generated into superheated steam by
a 12kw heater 25 to
simulate a 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 a 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 produced steam
6 from flow 8 (indicated 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,
k 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
63


CA 02770651 2012-02-29

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
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,
k 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

[170] Example 10: The following table are the simulation results for the
process described 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 a temperature of 20 C. The system
is at a low pressure,
close to atmospheric pressure. The produced water 1 is mixed with superheated
steam 7 at 535 C. Solid
contaminates 3 are removed from separator 21. The produced steam 4 is divided
into two flows - portion
of the produced steam (70%) at a temperature 99.7 C is recycled, using
mechanical compression, an
ejector (not shown) or any other means, to generating the recycle flow. The
recycled steam 5 is heated
with a 12kw heat source to generate superheated steam 7 at a temperature of
534 C. The remaining 30%
of the produced steam 8 is condensed by direct contact mixture with process
water 9 at a temperature of
20 C to generate 80 C process water that can used in the extraction process.
The produced steam 4 can be
further cleaned with any dry or wet commercially available cleaning systems,
such as 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 of hot water is generated in this simulation from a 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
N-Pentane 0.32 1.05 0.00 1.05 0.73 0.73
64


CA 02770651 2012-02-29

N-Hexane 0.14 I 0.45 I 0.00 1 0.45 1 0.31 I 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,
k 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

[171] Example 11: The following table are the simulation results for the
process described 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 a temperature of 20 C. The system
is at a low pressure,
close to atmospheric pressure. The produced water 1 is mixed with superheated
steam 7 at 492 C. Solid
contaminates 3 are removed from separator 21. The produced steam is condensed
by direct contact
mixture with process water 9 at a temperature of 20 C to generate 80 C process
water that can be used in
the extraction process. A portion of the produced water is heated in boiler 25
to generate superheated
steam. The flow to produce the steam 5 can be further treated to remove
contaminates to increase its
quality to BFW quality water. Another option is to split the produced steam 4,
scrub a portion, condense
the clean scrubbed steam to water, possibly with water from an exterior
source, and use 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 -20.31 -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 02770651 2012-02-29

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

[172] Example 12: The following table is a simulation of the method described
in Figure 3 that
illustrated producing steam with the use of a heat source without using an
external source for the driving
steam and with the use of a high pressure steam ejector to generate the
internal flow in the system. SD-
DCSG 30 includes a hot and dry steam injection 36. In the simulation, the
driving steam temperature was
around 480 C - a typical re-heater temperature. Low quality produced water 34,
at a temperature of 200 C
with solids and bitumen contaminates, is injected into the steam. Inside the
SD-DCSG the injected liquid
water is converted into steam at 280 C temperature and is at the same 600psi
pressure as the dry driving
steam 36. An 80% portion of the generated steam 32 is recycled through the
ejector. The ejector is only
designed to create the steam flow through heat exchanger 38 and create the
flow through the SD-DCSG
30. High pressure steam 40 at a pressure of 1450psi and a temperature of 311 C
is injected through ejector
to generate the required over pressure and flow in line 36. The produced low
pressure steam flows to heat
exchanger 38 where 12kw heat is added to the recycled steam flow 32 to
generate a heated "dry" steam 36
at 480 C. This steam is used to drive the SD-DCSG as it is injected into the
steam generation enclosure 30
and the excess heat energy is used to evaporate the injected water and
generate additional steam 31 at 280
C. The produced steam 31 or just the recycled produced steam 32 can be cleaned
of solids carried with the
steam gas by an additional commercially available system (not shown).

Inside
SD-
Line DCSG Ejector
Number 34 30 35 31 32 Discharge 36 33 40
T, C 200 280.46 280.46 280.46 280.45 279.93 480.69 280.45 311.59
66


CA 02770651 2012-02-29

Press., psig 600 600.00 600.00 600.00 600.00 601.47 600.00 600.00 1450.38
Vapor
Fraction 0 1.00 0.00 1.00 1.00 1.00 1.00 1.00 1.00
Enthalpy, - - - - -
kW 92.863 387.97 -4.78 383.14 302.80 -306.85 295.10 -80.49 -4.05
Total Flow,
kg/hr 22.5 108.49 1.22 107.26 84.82 85.92 85.99 22.55 1.10
Water,
kg/hr 20.925 105.37 0.00 105.37 83.27 84.37 84.44 22.14 1.10
Solids 1.125 1.13 1.13 0.00 0.00 0.00 0.00 0.00 0.00
Bitumen 0.450 1.995 0.100 1.895 1.545 1.545 1.545 0.411 0.000

[173] Example 13: The following table simulates the process as described in
Figure 3 for
insitue oilsands thermal extraction facilities, like SAGD, for 600psi
pressures. The water feed is hot
produced water at 200 C that includes solids and bitumen. The heat source Q
for the simulation was
12KW. A portion of the heavy hydrocarbons are separated with the solids.

Flow Number 34 35 31 32 36 33
T, C 200 283.24 283.24 283.08 486.97 283.08
Press., psig 600 600.00 600.00 600.00 600.00 600.00
Vapor Fraction 0 0.00 1.00 1.00 1.00 1.00
Enthalpy, kW -92.863 -4.78 -380.72 -304.70 -292.68 -76.17
Total Flow,
kg/hr 22.5 1.23 106.83 85.56 85.56 21.39
Water, kg/hr 20.925 0.00 104.77 83.85 83.85 20.96
Solids 1.125 1.13 0.00 0.00 0.00 0.00
Bitumen 0.450 0.108 2.055 1.713 1.713 0.428

[174] The table and the graph in Figure 30 show the produce steam amount as a
function of the feed water temperature in the system, as described in example
13. The simulation
shows that with 20 C feed water, 15.1kg/hr steam at 600psi and 280 C will be
produced from 12kw
heat source. With 240 C produced feed water, 23.5kg/hr steam at 600psi and 280
C will be produced
from 12kw heat source. There is an advantage to using hot produced water as
the heat energy within
the produced water: it will increase the amount of the produced steam. A
portion of the hydrocarbons
with the produced water will be converted to gas and flow with the produced
steam.

67

A single figure which represents the drawing illustrating the invention.

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BETZER, MAOZ
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