Canadian Patents Database / Patent 2715619 Summary

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Claims and Abstract availability

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(12) Patent Application: (11) CA 2715619
(51) International Patent Classification (IPC):
  • F22B 1/14 (2006.01)
  • E21B 43/24 (2006.01)
  • F22B 33/00 (2006.01)
(72) Inventors :
(73) Owners :
(71) Applicants :
(74) Agent: NA
(74) Associate agent: NA
(45) Issued:
(22) Filed Date: 2010-09-13
(41) Open to Public Inspection: 2011-05-12
(30) Availability of licence: N/A
(30) Language of filing: English

(30) Application Priority Data:
Application No. Country/Territory Date
2694847 Canada 2010-02-26
2684817 Canada 2009-11-12
2686140 Canada 2009-11-23

English Abstract

The present invention is a system and method for steam production for
extraction of heavy
bitumen. The method includes generating steam, mixing the steam with water
containing solids and
organics, separating solids, and injecting the steam through an injection well
or using it above ground
for oil recovery. The system includes a steam drive direct contact steam
generator. The water feed of
the present invention 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.

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


I claim:

1. A method for steam production for extraction of heavy bitumen, said method
comprising the
steps of:

(a) generating or heating steam through indirect heat exchange;

(b) mixing said steam gas with liquid water having solids and organics so as
to transfer
said liquid water from a liquid phase to a gas phase;

(d) removing solids to produce solids free gas phase steam;
(h) using produced gas phase steam to recover oil.

2. A system for producing steam for extract heavy bitumen, the system

a combustion heater, mixing fuel with oxidation gases therein, forming a
combusting the mixture, recovering combustion heat to generate or heat steam;

a steam drive direct contact steam generator, mixing steam generated by said
with water containing levels of solids therein to form a steam stream and
solids discharged streams,
wherein said steam drive direct contact steam generator is in fluid connection
to said heater; and

an enhanced oil recovery facility in fluid connection to said steam drive
direct contact
steam generator.

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

CA 02715619 2010-09-13


1. Field of the Invention

[01] This application relates to a system and method for producing steam from
contaminated water feed for Enhanced Oil Recovery (EOR). This invention
relates to processes for
directly using steam energy, preferably superheated dry steam, for generating
additional steam from
contaminated water by direct contact, and using this produced steam for
underground injection for
Enhanced Oil Recovery. The high pressure drive steam is generated using
commercially available, non-
direct steam boiler, co-gen, OTSG or any available steam generation system.
The contaminates, like
suspended or dissolved solids within the low quality water feed, can be
removed in a stable solid
(former Liquid Discharge) system. The system can be integrated with combustion
gas fired DCSG (Direct
Contact Steam Generator) for consuming liquid waste streams.

[02] The injection of steam into heavy oil formations was proven to be an
effective method
for FOR and it is the only method currently used commercially for recovery of
bitumen from deep
underground oilsand formations in Canada. It is known that FOR can be achieved
where combustion
gases, mainly C02, are injected into the formation, possibly with the use of
DCSG as described in my
previous applications. The problem is that oil producers are reluctant to
implement significant changes
to their facilities, especially if they include changing the composition of
the injected gas to the
underground formation and the risk of corrosion in the carbon steel pipes due
to the presence of the
C02. Another option to fulfill this requirement and generate steam from low
grade produced water with
ZLD is to operate the DCSG with steam instead of a combustion gas mixture that
includes, in addition to
steam, other gases like nitrogen, carbon dioxide, carbon monoxide and other
gases. The driving steam is
generated by a commercially available non-direct steam generation facility.
The driving steam is directly
used to transfer liquid water into steam and solid waste. In FOR facilities
most of the water required for
steam generation is recovered from the produced bitumen-water emulsion. The
produced water has to
be extensively treated to remove the oil remains that can damage the boilers.
This process is expensive
and consumes large amount of chemicals. The SD-DCSG (Steam Drive - Direct
Contact Steam Generator)
can consume the contaminated water feed for generating steam. The SD-DCSG can
be stand alone
system or can be integrated with combustion gas DCSG as described in this

CA 02715619 2010-09-13

[03] The steam for the SD-DCSG can be provided directly from a power station.
The most
suitable steam will be the medium pressure, super-heated steam as typically
fed to the second or third
stage of steam turbine. A cost efficient, hence effective system will be to
employ a high pressure, single
stage steam turbine to generate electricity. The discharge steam from the
turbine, at a lower pressure,
can be recycled back to the boiler re-heater to generate a super heated steam
which is effective as a
driving steam. Due to the fact that the first stage turbine, which is the
smallest size turbine, produces
most of the power (due to a higher pressure), the cost per Megawatt of the
steam turbine will be
relatively low. The efficiency of the system will not be affected as the
superheated steam will be used to
drive the SD-DCSG directly and generating injection steam for enhanced oil
recovery unit with Zero
Liquid Discharge (ZLD). A ZLD facility is more environmentally friendly
compared to a system that
generates reject water and sludge.
[04] The definition of "Steam Drive - Direct Contact Steam Generation" (SD-
DCSG) is that
steam is used to generate additional steam from direct contact heat transfer
between the liquid water
and the combustion gas. This is accomplished through the direct mixing of the
two flows (the water and
the steam gases). In the SD-DCSG, the driving steam pressure is similar to the
produced steam pressure
and the produced steam is a mixture of the two.
[05] The driving steam is generated in a Non-Direct Steam Generator (like a
steam boiler
with a steam drum and a mud drum) or "Once Through Steam Generator" (OTSG)
COGEN that uses the
heat from a gas turbine to generate steam or any other available design. The
heat transfer and
combustion gases are not mixed and the heat transfer is done through a wall
(typically a metal wall),
where the pressure of the generated steam is higher than the pressure of the
combustion. This allows
for the use of atmospheric combustion pressure. The product is pure steam (or
a steam and water
mixture, as in the case of the OTSG) without combustion gases.
[06] There are patents and disclosures issued in the field of the present
invention. US patent
No. 6,536,523 issued to Kresnyak et at. on March 25, 2003 describes the use of
the blow-down heat as
the heat source for water distillation of de-oiled produced water in a single
stage MVC water distillation
unit. The concentrated blow-down from the distillation unit can be treated in
a crystallizer to generate
solid waste.

[07] US Patent application 12/702,004 filed by Minnich et al. and published on
August 12,
2010 describes a heat exchanger that operates on steam for generating steam in
an indirect way from
low quality produced water that contains impurities. In this disclosure, steam
is used indirectly to heat
the produced water that include contaminates. By using steam as the heat
transfer medium the direct

CA 02715619 2010-09-13

exposure of the low quality water heat exchanger to fire and radiation is
prevented, thus there will be
no damage due to the redaction of the heat transfer. The concentrated brine is
collected and delivered
to disposal or to multi stage evaporator to recover most of the water and
generates a ZLD (Zero Liquid
discharge) system. The heat transfer surfaces between the steam and the
produced water will have to
be clean or the produced water will have to be treated. The concentrated
brine, possibly with organics,
will be treated in a low pressure, low temperature evaporator to increase
their concentration; the
higher the concentration is, the lower the temperature. In my application, due
to the direct approach of
the heat transfer, the system in ZLD with the highest concentration, possibly
up to 100% liquid recovery
while generating solid waste, is at the first stage at the higher temperature
due to the direct mixture
with the superheated dry steam that converts the liquid into gas and solids.
[08] US patent No. 7,591,309 issued to Minnich et al. on September 22, 2009
describes the
use of steam for operating a pressurized evaporation facility where the
pressurized vapor steam is
injected into underground formation for EOR. The steam heats the brine water
which is boiled to
generate additional steam. To prevent the generation of solids in the
pressurized evaporator, the
internal surfaces are kept wet by liquid water and the water is pre-treated to
prevent solid build up. The
concentrated brine is discharged for disposal or for further treatment in a
separate facility to achieve a
ZLD system. To achieve ZLD, the brine evaporates in a series of low pressure
evaporators (Multi Effect

[09] US patent No. 6,733636, issued to Heins on May 11, 2004, describes a
produced water
treatment process with a vertical MVC evaporator.

[10] US Patent No. 7,578,354, issued to Minnich et al. on August 25, 2009,
describes the use
of MED for generating steam for injecting into an underground formation.

[11] US Patent No. 7,591,311, issued to Minnich et al. on September 22, 2009,
evaporating water to produce distilled water and brine discharge, feeding the
distilled water to a boiler,
and injecting the boiler blow-down water from the boiler to the produced
steam. The solids and possibly
volatile organic remains are carried with the steam to the underground oil
formation. The concentrated
brine is discharged in liquid form.

[12] This invention's method and system for producing steam for extraction of
bitumen includes the steps as described in the patent figures.

[13] The advantage and objective of the present invention are described in the
application and in the attached figures.

CA 02715619 2010-09-13

[14] These and other objectives and advantages of the present invention will
apparent from a reading of the attached specifications and appended claims.


[15] The method and system of the present invention for steam production for
extraction of
heavy bitumen by injecting the steam to an underground formation or by using
it as part of an above
ground oil extraction facility includes the following steps: (1) Generating a
super heated steam stream.
The steam is generated by a commercially available non-direct steam generation
facility , possibly as
part of a power plant facility; (2) Using the generated steam as the hot gas
to operate a DCSG (Direct
Contact Steam Generator); (3) Mixing the super heated steam gas with liquid
water with significant
levels of solids, oil contamination and other contaminate; (4) Directly
converting liquid phase water into
gas phase steam; (5) Removing the solid contaminates that were supplied with
the water for disposal or
further treatment; (6) Using the generated steam for EOR, possibly by
injecting the produced steam into
an underground oil formation through SAGD or CSS steam injection well.
[16] In another embodiment, the invention can include the following steps: (1)
Generating a
super heated steam stream. The steam is generated by heating a steam stream in
non-direct heat
exchanger; (2) Using the generated steam as the hot gas to operate a DCSG
(Direct Contact Steam
Generator); (3) Mixing the super heated steam gas with liquid water with
significant levels of solids, oil
contamination and other contaminates; (4) Directly converting liquid phase
water into gas phase steam;
(5) Removing the solid contaminates that were supplied with the water for
disposal or further
treatment; (6) Recycling a portion of the generated steam back to the heating
process of (1) to be used
as hot gas operating the DCSG.

[17] In another embodiment, part of the generating steam is condensed and used
to wash
the produced steam from solid particles in a wet scrubber. Chemicals can be
added to the liquid water
to remove contaminates. A portion of the liquid water is recycled back and
mixed with the superheated
steam to transfer it into gas and solids. A portion from the scrubbed
saturated steam flow can be
recycled and heated to generate a super heated "dry" steam flow to drive the
SD-DCSG and change the
liquid flow into steam.

[18] In another embodiment, the scrubbed saturated steam, after the solids
were removed,
can be condensed to generate contaminate free liquid water, at a saturated
temperature and pressure.
The liquid water can be pumped and fed into a commercially available non-
direct steam boiler for

CA 02715619 2010-09-13

generating super heated steam to drive the SD-DCSG for transferring the liquid
contaminated water into
gas and solids.
[19] In another embodiment, the SD-DCSG is integrated with DCSG that uses
gases as the heat source. In that embodiment, the discharge from the SD-DCSG
can be in a liquid form
and it can be used as the water source for the combustion gas driven DCSG.
[20] The present invention can be used to treat contaminated water by SD-DCSG
in different
industries like the power industry or chemical industry where there is a need
to recover the water from
contaminated water stream to generate steam with zero liquid discharge.
[21] The system and method different aspects of the present invention are
clear from the
following figures.


[22] FIGURES 1, and 1A show the conceptual flowchart of the method and the
[23] FIGURE 2 shows a block diagram of the invention. Flow 9 is superheated
steam. The
steam pressure can be from 1 to 150 bar and the temperature can be between
150C and 600C. The
steam flows to enclosure 11 which is a SD-DCSG. Contaminated produced water 7,
possibly with organic
contaminates, suspended and dissolved solids, is also injected into enclosure
11 as the water source for
generating steam. The water 7 evaporates and is transferred into steam. The
remaining solids 12 are
removed from the system. The generated steam 8 is at the same pressure as that
of the drive steam 9
but at a lower temperature as a portion of its energy was used to drive the
liquid water 7 through a
phase change. The generated steam is also at a temperature that is close to
the saturated temperature
of the steam at the pressure inside enclosure 11. The produce steam can be
further treated 13 to
remove carry-on solids, reducing its pressure and possibly removing additional
chemical contaminates.
Then the produced steam is injected into an injection well for EOR.

[24] FIGURE 2A shows a schematic of a vertical SD-DCSG. Dry steam 9 is
injected to vessel 11
at its lower section. At the upper section, water 7 isinjected 3 directly into
the up-flow stream of dry
steam. The water evaporates and is converted to steam at lower temperature but
at the same pressure.
The 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-

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DCSG enclosure 11. The solids 12 are removed from the system from the bottom 1
of the vertical
enclosure where they can be disposed of or further treated.
[25] FIGURE 2B shows a block diagram of the invention. This figure is similar
to Figure 2 but
with an additional solids removal system as described in Block 15. Block 15
can include any commercially
available Solid - Gas separation unit. In this particular figure, cyclone
separator 19 and electrostatic
separation are presented. High temperature filters, that can withstand the
steam temperature, possibly
with a back-pressure cleanup system, can be used as well. The steam flow
leaving the SD-DCSG can
include solids from the contaminate water 7. A portion of the solids 12 can be
recovered in a dry or wet
form from the bottom of the steam generation enclosure 11. The carry-on solids
14 can be recovered
from the gas flow 8 in a dry form for disposal or for further treatment.
[26] FIGURE 2C is another embodiment of a reaction chamber apparatus of a high-
steam drive direct contact steam generator of the present invention. A similar
structure can be used
with DCSG that uses combustion gas as the heat source to convert the liquid
water into steam. A
counter-flow horizontally-sloped pressure drum 10 is partially filled with
chains 11 that are free to move
inside the drum and are internally connected to the drum wall. A parallel flow
design can be used as
well. The chains increase the heat transfer and removes solids build-up. Any
other design that includes
internal embodiments that are free to move or moving with the rotating
enclosure and lifting solids and
liquids to enhance their mixture with the flowing gas can be used as well. The
drum 10 is a pressure
vessel and is continually rotating, or rotating at intervals. At a low point
of the sloped vessel 10, hot dry
steam 8 is generated by a separate unit, like the pressurized boiler (not
shown), and is injected into the
enclosure 8. The boiler is a commercially available boiler that can burn any
available fuel like coal, coke,
or hydrocarbons such as untreated heavy low quality crude oil, VR (vacuum
residuals), asphaltin, coke,
or any other available carbon or hydrocarbon fuel. The pressure inside the
rotating drum can vary
between lbar and 100bar, according to the oil underground formation. The
vessel is partially filled with
chains 10 that are internally connected to the vessel wall and are free to
move. The chains 10 provide an
exposed regenerated surface area that works as a heat exchanger and
continually cleans the insides of
the rotating vessel. The injected steam temperature can be any temperature
that the boiler can supply,
typically in the range of 200C and 800C. Low quality water, like mature
tailing pond water, rich with
solids and other contaminants (like oil based organics) or contaminated water
from the produced water
treatment process are injected into the opposite higher side of the vessel at
section 4 where they are
mixed with the driving dry steam and converted into steam at a lower
temperature. This heat exchange
and phase exchange continues at section 3 where the heavy liquids and solids
move downwards,

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directly opposite to the driving steam flow. The driving steam injected at
section 2, which is located at
the lower side of the sloped vessel, moves upwards while converting liquid
water to gas. The heat
exchange between the dry driving steam to the liquids is increased by the use
of chains that maintain
close contact, both with the hot steam and with the liquids at the bottom of
the rotating vessel. The
amount of injected water is controlled to produce steam in which the dissolved
solids become dry or
high solids concentration slurry and most of the liquids become gases.
Additional chemical materials
can be added to the reaction, preferably with any injected water. The
rotational movement regenerates
the internal surface area by mobilizing the solids to the discharged point.
The heat transfer in section 3
is sufficient to provide a homogenous mixture of gas steam and ground - up
solids or high viscosity
slurry. Most of the remaining liquid transitions to gas and the remaining
solids are moved to a discharge
point 7 at the lower internal section of the rotating vessel near the rotating
pressurized drum 10 wall.
The solids or slurry are released from the vessel 10 at a high temperature and
pressure. They undergo
further processing, such as separation and disposal.
[27] FIGURE 3 is an illustration of one embodiment of the present invention
without using an
external source for the driving steam. SD-DCSG 30 includes a hot and dry steam
injection 36. The steam
is flowing upwards where low quality water 34 is injected to the up flow
steam. At least a portion of the
injected water is converted into steam at a lower temperature and at the same
pressure as the dry
driving steam 36. The generated steam can be saturated ("wet") steam at a
lower temperature than the
driving steam. A portion of the generated steam 32 is recycled through
compressing device 39. The
compression is only designed to create the steam flow through heat exchanger
38 and create the up
flow in the SD-DCSG 30. The compressing unit 39 can be a mechanical rotating
compressor. Another
option is to use high pressure steam 40 and inject it through ejectors to
generate the required over
pressure and flow in line 36. The produced low pressure steam 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). The produced steam 31 or just the
recycled produced steam 32 can
be cleaned from solids carried with the steam gas by an additional
commercially available system (not
shown). The system can include solid removal; this heat exchanger can be any
commercially available
design. The heat source can be fuel combustion where the heat transfer can be
radiation, convection or
both. Another possibility can be to use the design of the re-heat heat
exchanger typically used in power

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stations to heat the medium / low pressure steam after it is released from the
high pressure stages of
the steam turbine.
[28] FIGURE 3A is an illustration of one embodiment of the present invention.
It is similar to
Figure 3 with the use of a rotating SD-DCSG. The driving superheated ("dry")
steam 36 is injected into
rotating pressurized enclosure 30. The rotating SD-DCSG enclosure consumes
liquid water 34, possibly
with solid and organic contaminations, and generates lower temperature steam
31 and solid waste 35
that can be disposed in a landfill and support traffic. The rotating SD-DCSG
30 is described in Figure 2C.
[29] FIGURE 4 is an illustration of one embodiment of the present invention,
where the
generated steam 44 is saturated and is washed by saturated water in a wet
scrubber 40 where
additional steam is generated. BLOCK 1 includes the system as described in
FIGURE 3 where BLOCK 32
can include solid removal as means to remove solid particles from the gas
(steam) flow. BLOCK 3
generates steam 33 and stable waste 35. The generated steam 33 can contain
carry-on solid particles
and contaminates that might create problems of corrosion or solids build ups
in the high temperature
heat exchanger. One way to remove the solid contaminates is by a commercially
available solid-gas
separation unit, as described in Figure 2B or with any other prior art solids
removal method. However,
there is an advantage to wet scrubbing of solids and possible other gas
contaminates. To improve the
removal of the solids and other contaminates, the steam 33 is directed to a
wet scrubber. In one
embodiment, the wet scrubber generates the liquid water for its operation.
This is done by an internal
heat exchanger that recovers heat from the steam and generates condensate
water. The condensate
liquid water is used for scrubbing the flowing steam in vessel 40. The
condensate is recycled 41 and used
to wash the steam and is used as a means to improve the heat transfer. Low
quality water from the oil-
water separation process, fine tailing water from tailing pond or from any
other source is pre-heated
through heat exchanger 42 while recovering heat from the produced steam 34
generated by the SD-
DCSG 30. The condensate is recycled in the wet scrubber to wash the steam.
Additional chemicals can
be added to the condensate to remove gas contaminates. A portion of the
condensate with the solids
and other contaminates 43 is removed from vessel 40 to maintain the
contamination concentration of
the condensate constant. Additional low quality water 47A can be added to the
SD-DCSG without pre-
heating as to prevent excessive cooling of the produced steam 33 and the
generation of excessive
condensate. The generated steam after going through the wet scrubber is clean
and saturated ("wet")
steam. A portion of the clean steam 45 is directed through trough heat
exchange 38 to generate "dry"
steam to drive the SD-DCSG 30 with sufficient thermal energy to convert the
low quality water feed 34
into steam. The flow through the heat exchanger and inside the vessel 30 is
generated by any suitable

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commercial unit that can be driven by mechanical energy or a jet energy driven
compression unit. The
produced clean saturated steam 46 can be injected into an underground
reservoir, like SAGD, for oil
recovery, it can also be used for heating process water for tar separation or
for any other process that
consumes steam.

[30] FIGURE 5 is a schematic diagram of one embodiment of the invention that
wet scrubbed, clean saturated steam. BLOCK 1 includes a SD-DCSG 30 as
previously described. The
generated steam 31 can be cleaned from solids in commercially unit 32,
previously described. Low
quality water 34, like MFT (Mature Fine Tailings), produced water or water
from any other available
source can be injected to the SD-DCSG 30. Solids 35 carried by the water 34
are removed. The SD-DCSG
30 is driven by superheated ("dry") steam that supplies the energy needed for
the steam generation
process. The dry steam 36 is generated by a commercially available boiler as
described in BLOCK 4. BFW
(Boiler Feed Water) 49 is supplied to BLOCK 4 for generating the driving
steam. The boiler facility can
include an industrial boiler, OTSG, COGEN combined with gas turbine, steam
turbine discharge re heater
or any other commercially available design that can generate dry steam 36 that
can drive the SD-DCSG
30. In the case where the boiler consumes low quality fuel, like petcoke or
coal, commercially available
flue gas treatment will be used. There is a lot of prior art knowledge as for
the facility in BLOCK 4 as it is
similar to the facility that is used all over the world for generating
electricity. The generated steam from
the SD-DCSG 37 is supplied to BLOCK 2 that includes a wet scrubber. The wet
scrubber 50 can contain
chemicals like ammonia or any other chemical additives to remove contaminates.
The exact chemicals
and their concentration will be determined based on the particular
contaminates in the low quality
water that is used. The contamination levels are much lowerthan in direct
fired DCSG where the water is
directly exposed to the combustion products as described in my previous
patents. Liquid water 48 is
injected to the wet scrubber vessel 50 to scrub the contaminates from the up-
flowing steam 37. Liquid
water 51 that includes the scrubbed solids are removed from vessel 50 and
recycled back to the SD-
DCSG 30 together with the feed water 34. Depending on the particular feed
water quality 34, it can be
used in the scrubber. In that case stream 48 and 34 will have the same
chemical properties and be from
the same source. The scrubbed generated steam 45 generated at BLOCK 2 can be
used for extracting
and producing of heavy oil or for any other use.

[31] FIGURE 5A is an illustration of one embodiment of the invention where a
portion of the
driving steam water is internally generated. The embodiment is described in
Figure 5 with the following
changes: BLOCK 3 was added and connected to BLOCK 2. This block includes a
direct contact condenser/
heat exchanger 40 that is designed to generate hot (saturated) boiler feed
water 46 and possibly

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saturated steam 44. The saturated steam 45 from scrubber 50 flows into the
lower section of a direct
contact heat exchanger / condenser 40 where BFW 42 is injected. From the
direct contact during the
heat-up of the BFW, additional water will be condensed generating additional
BFW 46. A portion of the
injected and generated water 48 is used in wet scrubber 50 to remove
contamination and is then
recycled back to the SD-DCSG 30. The additional condensate, clean BFW quality
water 49, is used in
BLOCK 4 for generating steam. The condensate is hot at the water or steam
saturated temperature in
the particle system pressure. Addition hot condensate can be generated and
recovered from the system
as hot process water for oil recovery or for other uses.

[32] FIGURE 5B is a schematic view of the invention with internal distillation
production for the boiler. The illustration is similar to the process
described in Figure 5A with a different
BLOCK 3. The low quality water 47 is heated with the saturated clean (wet
scrubbed) steam 45 from
BLOCK 2 (previously described). The saturated steam 45 condenses on the heat
exchanger 42, located
inside vessel 40, while generating distilled water 46. A portion of the
distilled water 48 is recycled to the
wet scrubber vessel 50 where it removes the solids and generates additional
wet steam from the
partially dry steam generated in the SD-DCSG 30 in BLOCK 1. Additional
distilled water 49, possibly after
minor treatment and chemical additives (not shown) to bring it to BFW
specifications, is directed to the
boiler in BLOCK 4 for generating the driving steam. The system can produce
saturated steam 44A or
saturated liquid distilled water 44B or both. The produced steam and water are
used for oil production
and process or for any other use.

[33] FIGURE 5C is a schematic diagram of the method that is similar to Figure
5B but with a
different type of SD-DCSG in Block 1. Figure 5C includes a vertical stationary
SD-DCSG. The dry driving
steam 36 is fed into vessel 30 where the low quality water 34 is fed above it.
Due to excessive heat, the
liquid water is converted into steam. The waste discharge at the bottom 35 can
be in a liquid or solid
form. BLOCKS 2, 3 and 4 are similar to the previous Figure 5B.

[34] FIGURE 6 is a schematic diagram of the present invention which includes a
and an FOR facility like SAGD for injecting steam underground. BLOCK 1 is a
standard commercially
available boiler facility. Fuel 1 and oxidizer 2 are combusted in the boiler
3. The combustion heat is
recovered through non-direct steam generator for generation of superheated dry
steam 9. The
combustion gases are released to the atmosphere or for further treatment (like
solid particles
removal, SOX removal, CO2 recovery etc.). The water that is fed to the boiler,
is fed from BLOCK 2
which includes a commercially available boiler treatment facility. The quality
of the supplied water is
according the particular specifications of the steam generation system in use.
The dry steam is fed

CA 02715619 2010-09-13

to SD-DCSG 10. Additional low quality water 7 is fed into vessel 11 where the
liquid water is
transferred to steam due to the excess heat in the superheated driving steam
9. The generated
steam 8, possibly saturated or close to being saturated steam, is injected
into an underground
formation through an injection well 16 for EOR. The produced emulsion 13 of
water and bitumen is
recovered at the production well 15. The produced emulsion is treated using
commercially available
technology and facilities in BLOCK 2, where the bitumen is recovered and the
water is treated for re-
use as a BFW. Additional make-up water 14, possibly from water wells or from
any other available
water source can be added and treated in the water treatment plant. The water
treatment plant
produces two streams of water - a BFW quality 6 stream as it is currently done
to feed the boilers
and another stream of contaminated water 7 that can include the chemicals that
were used to
produced the high quality BFW, oil contaminates, dissolved solid (like salts)
and suspended solids
(like silica and clay). The low quality flow is fed to the SD-DCSG 10 to
generate injection steam.

[35] FIGURE 6A is a schematic flow diagram of the integration between SD-DCSG
DCSG that uses the combustion gas generated by pressurized boiler. BLOCK 1
includes a DCSG with
non-direct heat exchanger boiler as described in my previous applications.
Carbon or hydrocarbon
fuel 2 is mixed with an oxidizer that can be air, oxygen or oxygen enriched
air 1 and combusted in a
pressurized combustor. Low quality water 12 discharged from the SD-DCSG is fed
into the
combustion unit to recover a portion of the combustion heat and to generate a
stream of steam and
combustion gas mixture 4. The solid contaminates 18 are removed in a solid or
stable slurry form
where they can be disposed of. The steam and combustion gas mixture 4 is
injected into injection
well 17 for EOR. Injection well 17 can be a SAGD "old" injection well where
the formation oil is partly
recovered and large underground volumes are available, as well as where
corrosion problems are
not so crucial as the well is approaching the end of its service life. Another
preferable option for
using the steam and combustion gas mixture is to inject it into a formation
that is losing pressure
and needs to be pressurized by the injection of addition non-condensable gas,
together with the
steam. A portion of the combustion energy is used to generate superheated dry
steam in a boiler
type heat exchanger 5. The generated steam 9 is driving the SD-DCSG 10. The
water for the non-
direct boiler 5 is supplied from the 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)

CA 02715619 2010-09-13

facility. The steam from the SD-DCSG 8 is injected into an underground
formation through an
injection well 16 for EOR.
[36] FIGURE 7 is a schematic view of an integrated facility of the present
invention with
a commercially available steam generation facility and FOR for heavy oil
production. The steam for
FOR is generated using a lime softener based water treatment plant and OTSG
steam generation
facility. This type of configuration is most common in FOR facilities in
Alberta. It recovers bitumen
from deep oil sand formations using SAGD, CSS etc. Produced emulsion 3 from
the production well
54, is separated inside the separator facility to bitumen 4 and water 5. There
are many methods
from separating the bitumen from the water. The most common one uses gravity.
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.
[37] In a standard facility, the sludge is disposed of in a landfill. The
sludge is semi-wet, and
hard to stabilize. The softened water 14 flows to a filter 15 where filter
waste is generated 16. The waste
is sent to an ion-exchange package 19, where regeneration chemicals 18 are
continually used and
rejected with carry-on water as waste 20. In a standard system, the treated
water 21 flows to an OTSG
where approximately 80% quality steam is generated 27. The OTSG typically uses
natural gas 25 and air
26 to generate steam. The flue gas is released to the atmosphere through a
stack 24. Its saturated steam
pressure is around 100bar and the temperature is slightly greater than 300C.
In a standard SAGD system
the steam is separated in a separator, to generate 100% steam 29 for FOR and
blow-down water. The
blow down water can be used as a heat source and also to generate low pressure
steam. The steam, 29
is delivered to pads, where it is processed and injected into the ground
through an injection well 53. In
the current method, additional dry superheated steam flow is produced to drive
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.

CA 02715619 2010-09-13

[38] 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 lon-
Exchange system 20. The reject streams are collected 33 and injected directly
33A into Steam Drive
Direct Contact Steam Generation 30 in BLOCK 1. The SD-DCSG can be vertical,
stationary, horizontal or
rotating. Dry solids 35 are discharged from the SD-DCSG, after most of the
liquid water is converted to
steam. The SD-DCSG generated steam 31 temperatures can vary between 120C and
300C. The pressure
can vary between lbar and 50 bar. The produced steam 32 can be injected
directly 45A into the
injection well 53, possibly after additional solids and contamination removal
in BLOCK 32. Another
option is to wash the generated steam in wet scrubber 50 in BLOCK 2. BLOCK 2
is optional and can be
bypassed by flows 33A and 45A. The produced steam from the SD-DCSG 31 is
injected into a scrubber
vessel 50 where the steam gas is washed with saturated water 48 that was
condensed from the
produced gas 31 or from additional liquid water supplied to the wet scrubber
vessel 50 to remove the
solid remnants and possibly chemical contaminates. Solid rich water 51 is
continually removed from the
bottom of vessel 50. It is recycled back to the SD-DCSG, where the solids are
removed in dry or semi-dry
form 35. The liquid water is converted back to steam 31. The saturated wash
water in vessel 50 is
generated by removing heat through non-direct heat exchange with the feed
water 33. A portion of the
steam condenses to generate washing liquid water at vessel 50. The liquid
water continually recycled to
enhance the washing and the wet scrubbing. The SD-DCSG is driven by
superheated steam generated by
the steam generator 23 or in a separate boiler or in a separate heat exchanger
within the boiler (re-
heater type heat is exchanged to heat steam to produce a superheated steam).
There are many varieties
of commercially available options to generate the dry steam needed to drive
the process in the SD-
DCSG. The generated clean steam 45 is injected into an underground formation
for EOR.

[39] FIGURE 8 is a schematic of the invention with an open mine oilsand
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

CA 02715619 2010-09-13

using the solvent recovery process- characterized by high fines content,
relatively high asphaltene
content, and residual solvent. (See "Past, Present and Future Tailings,
Tailing Experience at Albian
Sands Energy" a presentation by Jonathan Matthews from Shell Canada Energy on
December 8,
2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta).
A sand dyke 55
contains a tailing pond. The sand separates from the tailings and generates a
sand beach 56. Fine
tailings 57 are put above the sand beach at the middle-low section of the
tailing pond. Some fine
tailings are trapped in the sand beach 56. On top of the fine tailing is the
recycled water layer 58.
The tailing concentration increases with depth. Close to the bottom of the
tailing layer are the MFT
(Mature Fine Tailings). (See "The Chemistry of Oil Sands Tailings: Production
to Treatment"
presentation by R.J. Mikula, V.A. Munoz, O.E. Omotoso, and K.L. Kasperski of
Devon, Alberta, Natural Resources Canada on December 8, 2008 at the
International Oil Sands
Tailings Conference in Edmonton, Alberta). The recycled water 41 is pumped
from a location close to
the surface of the tailing pond (typically from a floating barge). The fine
tailings that are used for
generating steam and solid waste in this invention are the MFT. They are
pumped from the deep
areas of the fine tailings 43. MFT 43 is pumped from the lower section of the
tailing pond and is then
directed to the SD-DCSG in BLOCK 1 and in BLOCK 3. The SD-DCSG that includes
BLOCKS 1-4 is
described in Figure 5B. However, any available SD-DCSG that can generate gas
and solids from the
MFT can be used as well. Due to the heat from the superheated steam and
pressure inside the SD-
DCSG, the MFT turns into gas and solids as the water is converted to steam.
The solids are recovered
in a dry form or in a semi-dry, semi-solid slurry form. The semi-dry slurry
form is stable enough to be
sent back into the oilsand mine without the need for further drying to support
traffic. The produced
steam needed for extraction and froth treatment, is generated by a standard
steam generation
facility 61 used to generate the driving steam for the DCSG in BLOCK 1 or from
the steam produced
from the SD-DCSG 62. The generated saturated steam 47 is mixed with the
process water 41 in
mixing enclosure 45 to generate the hot water 52 used in the extraction
process in BLOCK 5. By
continually consuming the fine tailing water 43, the oil sand mine facility
can use a much smaller
tailing pond as a means of separating the recycled water from the fine
tailings. This solution will
allow for the creation of a sustainable, fully recyclable water solution for
the open mine oilsand

[40] FIGURE 9 is a schematic view of the invention with an open mine oilsand
facility and a prior art commercially available pressurized fluid bed boiler
that uses combustion coal
for power supply. Examples of pressurized boilers are the Pressurized
Internally Circulating

CA 02715619 2010-09-13

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. Water 62 is recycled water with high level of
contaminates 38, as
discharged from the SD-DCSG 28. Some portion or stream 38A can be injected
above the
combustion area to directly recover heat from the combustion gas to generate
steam. The boiler
includes an internal heat exchanger 63 to generate high pressure steam 51 to
drive the SD-DCSG.
The steam 51 is generated from steam boiler drum 52 with boiler water
circulation pump 58. The
boiler heat exchanger 63 recovers energy from the combustion. BFW 37 is fed to
the boiler to
generate steam 51. The steam can be heated again in a boiler heat exchanger
(not shown) to
generate a superheated steam stream. The steam used to drive the SD-DCSG 28.
The boiler
generates pressurized combustion gas and steam mixture 1 from the SD-DCSG
discharged water 24
at a pressure of 103kpa and up to 1.5Mpa and temperatures of 2000-9000. The
discharge flow is
treated in BLOCK 3 to generate a steam and combustion gas mixture for EOR. The
mixture 8 is
injected into an underground formation through an injection well 7. There is
no need to remove
solids from the combustion gas 1 because this gas is fed to the DCSG in Block
3 that works as a wet
scrubber and remove solids and possibly contaminated gas like SOx and NOx
while creating a steam
and combustion gas mixture. Solids from the fluid bed of the PFBC 55 can be
recovered to maintain
the fluid bed solids level. (This is a common practice in FBC (Fluid Bed
Combustion) and PFBC). The
fluid bed solids can be mixed with the DCSG solids from BLOCK 3 (not shown).
The pressurized
combustion gases leaving AREA#1 are mixed with the concentrate effluent from
SD-DCSG 28 and
possibly with other low quality waste water and slurry sources, like HLS/WLS
sludge produced by
SAGD/CSS water treatment plant (not shown). Block 2 includes a commercially
available FOR facility,
like SAGD, where the water and bitumen emulsion is treated to generate BFW
water quality and low
quality water that is fed into the SD-DCSG. There will be two types of
injection wells - for the
injection of pure steam from the SD-DCSG 6 and for the injection of a mixture
of steam and
combustion gases, mainly CO2 7. It is possible to combine the two types of FOR
fluids in one
production facility where the aging injection wells will be converted from
pure steam to a steam and
combustion gas mixture to pressurize the underground formation and increase
the bitumen
recovery due to the CO2 dissolved that increases the bitumen fluidity.

CA 02715619 2010-09-13

[41] 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 to a DCSG. It includes reduced capacity internal heat exchangers to
recover less
combustion heat. The reduction in the heat exchanger required capacity is
because more
combustion energy will be consumed due to the direct heat exchange with the
water within the fuel
slurry 2 and the additional injected solid rich water 52 leaving less
available heat to generate high
pressure steam through the boiler heat exchangers 56. The boiler produces high-
pressure steam 59
from distilled, de-mineralized feed water 37. The produced steam 59, or part
of it 31, can be re-
heated in re-heater 56 to generate super heated seam 32 to operate the SD-DCSG
in BLOCK 3. There
are several pressurized boiler designs for BLOCK 1 that can be modified with
direct water injections.
One example of such a design is the EBARA Corp. PICFB (see paper No. FBC99-
0031 Status of
Pressurized Internally Circulating Fluidized-Bed Gasifier (PICFG) development
Project dated May-16-
19, 1999 and US RE37,300 E issued to Nagato et al on July 31, 2001). Any other
available Pressurized Fluidized Bed Combustion (PFBC) can be used as well.
Another modification to
the fluid bed boiler can be reducing the boiler combustion pressure down to
102kpa. This will
reduce the plant TIC (Total Installed Cost) and the pumps and compressors'
energy consumption.
The superheated steam 32 is supplied to BLOCK 3 where it is used by the SD-
DCSG 28 for generating
additional steam from low quality water. BLOCK 2 includes a water treatment
facility as previously
described. The steam and combustion gas mixture stream 1 is supplied to BLOCK
2 where the water
and heat can be used for generating clean BFW by evaporation / distillation
facility. The pressure
energy in flow 1 can be used to separate CO2 from the NCG using commercially
available membrane
technologies. The combustion oxidizer, like air, 55 is injected at the bottom
of the boiler to maintain
the fluidized bed. High pressure 100% quality steam 59 is generated from
distilled water 37 through
heat exchange inside the boiler 51. The generated steam 59 can be further
heated in heat exchanger
56 to generate super-heated steam 32 that is used in BLOCK 3 as the driving
steam for the SD-DCSG
28. The steam generated in BLOCK 3 is injected, through an injection well 16,
into an underground

CA 02715619 2010-09-13

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
[42] 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 that
generates additional steam
from the concentrated brine 38 discharged from the MED in BLOCK 2. The
generated steam 8 is injected
into an underground formation 6. The liquid discharge 14 from SD-DCSG 11 is
injected into an internally
fired DCSG 15 in BLOCK 3. Carbon fuel 41, like petcoke or coal slurry, is
mixed with oxygen-rich gas 42
and combusted in a DCSG 15. Discharged liquids from the SD-DCSG 11 are mixed
with the pressurized
combustion gas to generate a stream of steam-rich gas and solids 13. To reduce
the amount of SO2,
limestone can be added to the brine water 14 or to the fuel 41 injected into
the DCSG, to react with the
SO2. The solids are separated in separator 16. The separated solids 17 are
discharged in a dry form from
the solids separator 16 for disposal. The steam and combustion gas 12 flows to
heat exchanger 25 and
condenser 28. The steam in gas flow 12 is condensed to generate condensate 24.
The condensate is
treated (not shown) to remove contaminants and generate BFW that is added to
the distillate BFW 29
then supplied to the steam generation facility. The NCG (Non-Condensation Gas)
40 is released to the
atmosphere or used for further recovery, like CO2 extraction. The heat
recovered in heat exchanger 28
is used to generate steam to operate the MED 30 (a commercially available
package). The water 1 fed to
the MED is de-oiled produced water, possibly with make-up underground brackish
water. The Multi
Effect Distillation takes place in a series of vessels (effects) 31 and uses
the principles of condensation
and evaporation at a reduced pressure. The heat is supplied to the first
effect 31 in the form of steam
26. The steam 26 is injected into the first effect 31 at a pressure of 0.2bar
to 12 bar. The steam
condenses while feed water 32 is heated. The condensation 34 is collected and
used for boiler feed
water 37. Each effect consists of a vessel 31, a heat exchanger, and flow
connections, 35. There are
several commercial designs available for the heat exchanger area: horizontal
tubes with a falling brine
film, vertical tubes with a rising liquid, a falling film, or plates with a
falling film. The feed water 32 is
distributed on the surfaces of the heat exchanger and the evaporator. The
steam produced in each
effect condenses on the colder heat transfer surface of the next effect. The
last effect 39 consists of the
final condenser, which is continually cooled by the feed water, thus
preheating the feed water 1. To

CA 02715619 2010-09-13

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.
[43] FIGURE 11A is a view of the present invention that includes a steam
generation facility,
SD-DCSG and MED water treatment plant. BLOCK 1 is a standard, commercially
available steam
generation facility for generating super heated driving steam 5. The driving
steam 5 is fed to SD-DCSG in
BLOCK 3. Discharged brine from the commercial MED facility in BLOCK 2 is also
injected to the SD-DCSG
15 and converted to steam and solid particles 13. The solids 17 are removed
for disposal. A portion of
the generated steam 12 is used to operate the MED through heat exchanger /
condenser 28. The
condensate 24, after further treatment (not shown), is used as BFW. The MED
produces distilled BFW 29
that is used to produce the driving steam at the boiler 7. The steam 8 is
injected through injection well 6
for EOR.

[44] 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

BLOCK 3 includes a commercially available thermal water distillation plant.

BLOCK 7 includes syngas treatment plant where part of the syngas can be used
for hydrogen
production etc.

BLOCK 5 includes a water-oil separation facility with the option of oily water
discharge for recycling
into the SD-DCSG.

BLOCK 4 includes SD-DCSG which generates the injection steam.
BLOCK 6 includes DCSG.

CA 02715619 2010-09-13

Carbon fuel 5 is injected with oxygen rich 6 gas to a pressurized gasifier 7.
The gasifier shown is a typical
Texaco (GE) design that includes a quenching water bath at the bottom. Any
other pressurized partial
combustion gasifier design can also be used. The gasifier can include a heat
exchanger, located at the
top of the gasifier (near the combustion section), to recover part of the
partial combustion energy to
generate high pressure steam. At the bottom of the gasifier, there is a
quenching bath with liquid water
to collect solids. Make-up water 13 is then injected to maintain the liquid
bath water level. The
quenching water 15, which includes the solids generated by the gasifier, is
injected into a DCSG 15
where it is mixed with the produced hot syngas discharged from the gasifier
12. The DCSG also
consumes the liquid water discharge 52 from the SD-DCSG 50. In the DCSG, the
water is evaporated into
pressurized steam and solids (which were carried with the water and the syngas
into the DCSG). The
DCSG generates a stream of gas and solids 16. The solids 19 are removed from
the gas flow by a
separator 17 for disposal. The solids lean gas flow 18 (after most of the
solids have been removed from
the gas) is injected into a pressurized wet scrubber 20 that removes the solid
remains and can generate
saturated steam from the heat in gas flow 18 as well. Solids rich water 25 is
continually rejected from
the bottom of the scrubber and recycled back to the DCSG 15. Heat 27 is
recovered from the saturated
water and syngas mixture 21 while condensing steam 21 to liquid water 35 and
water lean syngas 36.
The condensed water 35 can be used as BFW after further treatment to remove
contaminations (not
shown). The heat 27 is used to operate a thermal distillation facility in
BLOCK 3. There are several
commercially available facilities for this, like MSF (Multi Stage Flashing) or
MED (Multi Effect
Distillation). The distillation facility uses de-oiled produced water 30,
possibly with make-up brackish
water 31 and heat 27, to generate a stream of de-mineralized BFW 29 for steam
generation and a
stream of brine water 28, with a high concentration of minerals. The generated
brine 28 is recycled back
to the SD-DCSG 50 in BLOCK 4. The syngas can be treated in commercially
available facilities BLOCK 7 to
remove H2S using amine or to recover hydrogen. The treated syngas 37, together
with oxidizer 38, is
used as a fuel source in the commercially available steam generation facility
BLOCK 2. The super heated
steam 40 is generated in steam boiler 39 from the BFW 29. The steam from the
boiler 40, possibly
together with the steam generated by the gasifier 10, is injected into the SD-
DCSG 50 in BLOCK 4 where
additional steam is generated from low quality water 53. The generated steam
51 is injected into an
underground formation for EOR. The produced bitumen and water recovered from
production well 44
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

CA 02715619 2010-09-13

water, the chemical consumption can be reduced and the efficiency of the oil
separation unit can be

A single figure which represents the drawing illustrating the invention.

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Title Date
Forecasted Issue Date Unavailable
(22) Filed 2010-09-13
(41) Open to Public Inspection 2011-05-12
Dead Application 2016-09-14

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Filing $200.00 2010-09-13
Maintenance Fee - Application - New Act 2 2012-09-13 $50.00 2012-08-27
Maintenance Fee - Application - New Act 3 2013-09-13 $50.00 2013-09-11
Maintenance Fee - Application - New Act 4 2014-09-15 $50.00 2014-09-10
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