Canadian Patents Database / Patent 2752558 Summary

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(12) Patent: (11) CA 2752558
(54) English Title: STEAM DRIVEN DIRECT CONTACT STEAM GENERATION
(54) French Title: APPAREIL DE GENERATION DE VAPEUR A CONTACT DIRECT EXPLOITE PAR VAPEUR
(51) International Patent Classification (IPC):
  • F22B 1/14 (2006.01)
  • E21B 43/24 (2006.01)
(72) Inventors :
  • BETSER-ZILEVITCH, MAOZ (Canada)
(73) Owners :
  • BETSER-ZILEVITCH, MAOZ (Canada)
(71) Applicants :
  • BETSER-ZILEVITCH, MAOZ (Canada)
(74) Agent:
(74) Associate agent:
(45) Issued: 2020-10-27
(22) Filed Date: 2011-09-12
(41) Open to Public Inspection: 2012-03-13
Examination requested: 2016-09-06
(30) Availability of licence: N/A
(30) Language of filing: English

(30) Application Priority Data:
Application No. Country/Territory Date
2715619 Canada 2010-09-13
2728064 Canada 2011-01-10
2748477 Canada 2011-08-02

English Abstract


The present invention is a system and method for steam production for oil
production. 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, such as for
generating hot
process water. The system includes a steam drive direct contact steam
generator. 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.

French Abstract

La présente invention concerne un système et procédé de production de vapeur pour la production de pétrole. Le procédé consiste à produire de la vapeur, à mélanger de la vapeur avec de leau contenant des matières solides et des matières organiques, à séparer des matières solides et à injecter la vapeur à travers un puits dinjection ou à lutiliser au-dessus du sol pour la production de pétrole, comme pour générer de leau de traitement chaude. Le système comprend un générateur de vapeur à contact direct par déplacement par vapeur. Lalimentation en eau de la présente invention peut être de leau produite chaude séparée dune émulsion de pétrole produite et/ou de leau de mauvaise qualité repêchée des installations industrielles, comme les raffineries et les résidus dune mine de sables bitumineux.


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:
generating steam through indirect heat exchange;
mixing said steam with liquid water having solids and organics
contaminates, so as to transfer said liquid water from a liquid phase to a gas
phase; and
removing solids to produce a clean gas phase steam.
2. A method for steam production for oil production, said method comprising
the
steps of:
generating steam through indirect heat exchange;
using the generated steam energy to directly gasify liquid water with solids
and organics, so as to transfer said liquid water from a liquid phase to a gas
phase;
separating solids and the gas phase to produce a clean gas phase steam;
condensing the clean gas phase steam to generate heat and water; and
using the generated heat and water for oil production.
3. A system for producing steam for extract heavy bitumen, the system
comprising:
a heat exchanger means for indirectly generating superheated steam;
a steam drive direct contact steam generator, mixing said superheated
steam 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
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an oilsands heavy bitumen extraction facility in fluid connection with said
steam drive direct contact steam generator.
4. The method of any one of claims 1 and 2, wherein a portion of said clean
gas
phase steam is recycled and heated indirectly before being mixed with the
liquid water
having solids and organics contaminates.
5. The method of any one of claims 1, 2 and 4, wherein said generated steam is

generated in a boiler from treated water flow before mixed with said liquid
water having
solids and organics contaminates.
6. The method of any one of claims 4 and 5, further comprising the step of:
circulating a portion of the clean gas phase steam in a steam ejector,
wherein steam for operating said steam ejector is added to the clean gas phase
steam.
7. The method of any one of claims 1, 4-6, further comprising the step of:
injecting the produced clean gas phase steam to recover oil through an
injection well.
8. The method of any one of claims 1-2, 4-7, wherein the liquid water having
solids
and organics contaminates include solvents that converted to gas and become
part of the
produced clean gas phase steam.
9. The method of any one of claims 7 and 8, further comprising the step of:
adding solvents to the produced clean gas phase steam prior to injecting
underground.
10. The method of any one of claims 1-2, 4-9, further comprising the step of:
scrubbing at least a portion of the produced clean gas phase steam by
mixing with liquid water at a saturated temperature and recycling the
saturated
78

temperature water with the scrubbed contaminates back to the step of mixing
the
contaminated water with said steam.
11. The method of claim 10, further comprising the step of:
adding chemicals to said saturated scrubbing water so as to improve
scrubbing performance of contaminates.
12. The method of any one of claims 10 and 11, further comprising the step of:

using a portion of the scrubbed steam as recycle fluid through a heater to
generate at least a portion of said steam.
13. The method of any one of claims 2, 4-6 and 10-12, further comprising the
step
of:
separating non-condensable gases, having hydrocarbons and solvent
remains, from the condensed water; and
combusting said non-condensable gases generating said steam.
14. The method of any one of claims 1 and 4-12, further comprising the steps
of:
producing oil and water from a production well;
separating portion of the water from said oil to generate said liquid water
having solids and organics contaminates; and
mixing said produced liquid water having solids and organics contaminates
with said steam.
15. The system of claim 3, further comprising:
a SAGD production well producing a mixture of water, oil and gas; and
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a separator fluidly connected to the production well for separation portion of

the produce water from the oil for generating said water containing levels of
solids therein,
being fluidly connected to said direct contact steam generator.
16. The system of any one of claims 3 and 15, further comprising:
a heater for generating said superheated steam;
a high-pressure steam supply to an ejector; and
an ejector means for recycling a portion of said produced steam from said
direct contact steam generator to said heater to generate at least a portion
of the
superheated steam.
17. The system of any one of claims 15 and 16, wherein said direct contact
steam
generator and said heater are located on a SAGD well pad in proximity to the
steam
injection well.
18. A method for steam production for extraction of oil, said method
comprising
the steps of:
generating superheated steam through indirect heat exchange;
injecting fluid containing water having solids and organics contaminates
into said steam, so as to transfer said liquid water from a liquid phase to a
gas phase
while generating additional produce gas containing steam;
recovering said steam and said additional produce gas containing steam;
and
extracting oil with said steam and said additional produce gas containing
steam.

19. A method for steam production for SAGD oil extraction, said method
comprising the steps of:
generating steam using a boiler from a boiler feed water;
mixing produced fluid containing water with said steam;
evaporating at least a portion of the liquid water in said produced fluid
containing water to generate produce gas containing steam;
injecting said produce gas containing steam into a SAGD injection well to
extract oil; and
producing oil and water from SAGD production well.
20. A method for steam production for SAGD oil extraction, said method
comprising the steps of:
generating superheated gas flow containing steam;
spreading fluid containing water into said superheated steam to evaporate
a portion of said fluid containing water and generating produced gas
containing steam;
and
injecting said produce gas containing steam through a SAGD injection well
into an underground formation to extract oil.
21. The method any one of claims 1-2, 4-14 and 18-20, wherein said liquid
water
is at saturate temperature.
22. The method any one of claims 1-2, 4-14 and 18-21, wherein said steam is
superheated.
23. The method of any one of claims 1, 4-12 and 18 -22, further includes:
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producing fluid containing water and oil from an underground formation;
and;
separating said produced fluid containing water from said produce fluid
containing water and oil.
24. The method of any one of claims 18-23, further includes:
separating a portion of said produce gas containing steam; and
heating said separated portion of said produce gas containing steam to
generate said superheated flow containing steam.
25. The method of claim 24, further include:
generating concentrated liquid flow wherein said concentrated flow includes
contaminates supplied with said produce liquid containing water;
separating at least a portion from said concentrated liquid flow; and
recovering heat from said portion of said concentrated liquid flow.
26. The method any one of claims 20-25, wherein:
spraying said fluid containing water into a flow of said superheated flow
containing steam.
27. The method any one of claims 1, 4-12, 14 and 18-26, wherein the liquid
water
having contaminates is at a saturated temperature and collected at an
enclosure bottom,
where the superheated steam is flowing into the enclosure and some of the
bottom
saturated temperature liquid water is pumped and spread into the superheated
steam
flow to enhance the direct contact heat transfer from the superheated steam to
the
saturated temperature liquid water while evaporating some of the spread liquid
water.
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28. The method of any one of claims 18-27, further includes:
flowing said superheated flow containing steam in an upwards direction;
injecting said fluid containing water into the upwards flow as to directly
transfer heat from the superheated flow to the injected fluid containing water
to evaporate
at least a portion from said liquid water;
generating a flow of gas containing an additional steam and a flow of
concentrated liquid includes contaminates supplied with said produce liquid
containing
water; and
using said gas containing an additional steam to extract oil.
29. The method of claim 28, further includes:
collecting said concentrated liquid includes contaminates supplied with said
produce liquid containing water at a low point.
30. The method of any one of claims 28-29, further includes:
collecting said concentrated liquid flow in a sump; and
removing at least a portion from said concentrated liquid flow.
31. The method of any one of claims 4-12, 14 and 18-30, further includes:
injecting at least a portion of said produced steam into an
underground formation to produce oil.
32. The method of any one of claims 1, 4-14 and 18-31, further includes trays
to
enhance the mixing of the liquids and the gas containing superheated steam.
33. The system of any one of claims 3, 15-17, further includes trays in said
steam
drive direct contact steam generator.
83

34. The method of any one of claims 1, 4-14 and 18-32, further includes
rotating
elements to enhance the mixture of the liquid and superheated steam.
35. The system of any one of claims 3, 15-17, further include rotating
elements in
said steam drive direct contact steam generator.
36. The method of any one of claims 1-2, 4-14, 18-32 and 34, further includes:

combusting fuel to generate heat; and
heating flow containing steam to generate said superheated flow
containing steam.
37. The method of claim 36, further includes generating steam in a boiler with
said
combustion heat.
38. The method of any one of claims 37, further includes heating treated water
with
said combustion heat to generate pre-heated water; and
generating steam from said treated water.
39. The method of any one of claims 21-31 and 36-38, further includes:
recovering heat from said portion of said concentrated liquid flow; and
using said recovered heat to pre-heat treated water.
40. The method of any one of claims 1-2, 4-14, 18-31 and 36-39, wherein said
fluid
containing water contains at least one from a group containing: solvents,
hydrocarbons,
volatile hydrocarbons and oil emulsion.
41. The method of any one of claims 1-2, 4-14, 18-31 and 36-40, further
includes
removing solid and liquid contaminates from the produce gas containing steam.
42. The method of claim 41 wherein at least a portion of said produced gas
containing steam is scrubbed by saturated liquid fluid containing water.
84

43. The method of any one of claims 41 and 42, wherein at least a portion of
the
produced clean gas containing steam is re-cycled by steam ejector and heated
to
generate super-heated gas containing steam.
44. The method of any one of claims 2, 4-6, 13, 21-26 and 36-43, further
comprise
the steps of:
using the condensed clean gas phase steam as a process water for
oilsands bitumen production; and
using the condensed clean gas phase steam heat for heating additional
process water for oilsands bitumen production.
45. The method of claim 44, wherein said condensed clean gas phase steam
include solvents condensed together with the water.
46. The system of any one of claims 3, 15, 16, 33 and 35, further includes a
gas-
solids cyclone separator fluidly connected to said steam drive direct contact
steam
generator for separating solids from the steam stream.
47. The system of any one of claims 3, 15, 16, 33, 35 and 46, wherein said
steam
drive direct contact steam generator comprises of a horizontal rotating
enclosure for
mixing said superheated steam with said water containing levels of solids.
48. The system of claim 47 wherein said water containing levels of solids
comprised of oil sands tailings.
49. The system of any one of claims 47 and 48, wherein the solids discharge is
in
a dry form for landfill disposal.
50. The method of any one of claims 1-2, 4-14, 18-32 and 36-45, wherein:
the generated steam is superheated steam; and


combustion heat used to generate said generated superheated steam in a
heat exchanger is further used to generate additional steam from boiler feed
water.
51. The system of any one of claims 3, 15-17, 33, 35 and 46-47 further
com prising:
a SAGD production well producing a mixture of oil, water, and gas;
a separator fluidly connected to the SAGD production well for separating
portion of the produce water from the oil, for generating said water
containing levels of
solids therein, being fluidly connected to said direct contact steam
generator; and
a combustion heater for generating the superheated driving steam being
fluidly connected to said direct contact steam generator.

86

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

CA 02752558 2011-09-12
STEAM DRIVEN DIRECT CONTACT STEAM GENERATION
Field 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 EOR and it is the only method currently used commercially
for
recovery of bitumen from deep underground oilsands formations in Canada. It is
known
that EOR 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
1

CA 02752558 2011-09-12
EOR 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
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
2

CA 02752558 2011-09-12
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 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
3

CA 02752558 2011-09-12
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
4.1tons/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, 5.1tons/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 600p5i, 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 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
4

CA 02752558 2011-09-12
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.
[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

CA 02752558 2011-09-12
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.
[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.
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CA 02752558 2011-09-12
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 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
7

CA 02752558 2011-09-12
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 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
8

CA 02752558 2011-09-12
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 1ton/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 1ton/hour 25 C water
feed. The
simulation shows that at pressure of 263p5i, 4.9tons/hour of driving steam is
used to
gasify the water feed. At a higher pressure of 1450psi, 5.1tons/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
9

CA 02752558 2011-09-12
stream in a 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 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 or any other commercially available
chemicals) can be added to the wet scrubber to remove contaminates from the
steam
flow.
[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. 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 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 can be used to treat contaminated water using the
SD-DCSG in different industries, such as the power industry or chemical
industry where

CA 02752558 2011-09-12
there is a need to recover the water from a contaminated water stream to
generate
steam with zero liquid discharge.
[27] The system and method's different aspects of the present invention are
clear from the following figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[28] FIGURES 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the
method and the system.
[29] FIGURE 2 shows a block diagram of an embodiment of the invention.
[30] FIGURE 2A shows a schematic of a vertical SD-DCSG.
[31] FIGURE 2B shows a block diagram of the embodiment of the invention.
[32] 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.
[33] FIGURE 2D shows a schematic view of another embodiment of a vertical
SD-DCSG.
[34] FIGURE 2E shows a schematic view of a SD-DCSG integrated into an
open mine oilsands extraction plant.
[35] FIGURE 2F shows a schematic view of a SD-DCSG with a non-direct heat
exchanger to heat the process water.
[36] 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.
[37] FIGURE 3A is a schematic view of an illustration of another embodiment
of the present invention.
[38] FIGURE 3B is a schematic view of an illustration of a parallel flow SD-
DCSG according to Figure 3A.
[39] FIGURE 3C is a schematic view of an illustration of a SD-DCSG with a
stationary enclosure and an internal rotating element.
[40] 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.
11

CA 02752558 2011-09-12
[41] Figure 3E shows a schematic view of a parallel flow and a counter flow
steam drive direct contact steam generation system.
[42] Figure 3F shows a schematic view of a direct contact steam generating
system as shown in Figure 3E with solids separation.
[43] FIGURE 3G is a schematic view of a steam drive direct contact steam
generator apparatus.
[44] FIGURE 3H is a schematic view of another configuration of a steam drive
direct contact steam generator apparatus.
[45] FIGURE 31 is a schematic view of a steam drive direct contact steam
generator apparatus.
[46] 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.
[47] FIGURE 3K is a schematic view of an illustration of another embodiment
of the present invention.
[48] FIGURE 4 is a schematic view of an illustration of still another
embodiment of the present invention.
[49] FIGURE 5 is a schematic diagram of one embodiment of the invention that
generates wet scrubbed, clean saturated steam.
[50] 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.
[51] FIGURE 5B is a schematic view of the invention with internal distillation

water production for the boiler.
[52] FIGURE 5C is a schematic diagram of a method that is similar to Figure
5B but with a different type of SD-DCSG.
[53] FIGURE 6 is a schematic diagram of the present invention which includes
a SD-DCSG and an EOR facility.
[54] 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.
[55] FIGURE 6B is a schematic view of a direct contact steam generator with
rotating internals, dry solids separation, wet scrubber and saturated steam
generator.
12

CA 02752558 2011-09-12
[56] FIGURE 6Cis a schematic view of a SD-DCSG and heavy oil extraction
through steam injection.
[57] FIGURE 6D shows a schematic view of a SD-DCSG similar to the system
in Figure 6C.
[58] FIGURE 6E is a schematic view of the SD-DCSG with similarities to
Figure 6D and with externally supplied make-up HP steam.
[59] 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.
[60] FIGURE 7 is a schematic view of an integrated facility of the present
invention with a commercially available steam generation facility and for EOR
for heavy
oil production.
[61] FIGURE 8 is a schematic view of the invention with an open mine oilsands
extraction facility.
[62] FIGURE 9 is another schematic view of the invention with an open mine
oilsands extraction facility and a pressurized fluid bed boiler.
[63] FIGURE 10 is a schematic diagram of DCSG pressurized boiler and SD-
DCSG.
[64] 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.
[65] FIGURE 11A is a schematic view of the present invention that includes a
steam generation facility, SD-DCSG and MED water treatment plant.
[66] 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.
[67]
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.
[68] FIGURE 13 is a schematic view of the present invention for the generation

of hot water for oilsands mining extraction facilities.
13

CA 02752558 2011-09-12
[69] 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.
[70] 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.
[71] FIGURE 14 is a schematic view of one illustration of the present
invention
for the generation of pre-heated water.
[72] FIGURE 15 is a schematic view of the invention with an open mine
oilsands extraction facility.
[73] FIGURE 16 is a another schematic view of the invention with another
open mine oilsands extraction facility.
[74] FIGURE 17 is a schematic view of the invention with still another open
mine oilsand extraction facility.
[75] FIGURE 18 is a schematic view of the invention with yet another open
mine oilsands extraction facility.
[76] FIGURE 19 is a schematic view of an illustration of still another
embodiment of the present invention.
[77] FIGURE 20 is a schematic view of an illustration of yet another
embodiment of the present invention.
[78] 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.
[79] Figure 22 is a graph illustration of a simulation of the process as
described
in Figure 2A.
[80] Figure 23 is another graph illustration of a simulation of the process as

described in Figure 2A.
[81] Figure 24 is yet another graph illustration of a simulation of the
process as
described in Figure 2A.
[82] Figure 25 is a schematic view of the process of Example 7.
[83] Figure 26 is a schematic view of the process of Example 8.
[84] Figure 27 is a schematic view of the process of Example 9.
[85] Figure 28 is a schematic view of the process of Example 10.
14

CA 02752558 2011-09-12
[86] Figure 29 is a schematic view of the process of Example 11.
[87] Figure 30 is a graph illustration showing the amount of produced steam as

a function of the feed water temperature in the system.
DETAILED DESCRIPTION OF THE DRAWINGS
[88] FIGURES 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the
method and the system.
[89] 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.
[90] 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.

CA 02752558 2011-09-12
[91] 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 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.
[92] 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
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
burn 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
1bar 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
16

CA 02752558 2011-09-12
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 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
at a high temperature and pressure. They undergo further processing, such as
separation and disposal.
[931 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
17

CA 02752558 2011-09-12
converted to a lower temperature steam. 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.
[94] 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 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 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).
18

CA 02752558 2011-09-12
[95]
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. FTor 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
19

CA 02752558 2011-09-12
cleaning, like wet scrubbing, to remove contaminates like silica- is
indirectly heated by
combustion heater 18.
[96] 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

CA 02752558 2011-09-12
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.
[97] 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 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.
[98] 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.
[99] 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
21

CA 02752558 2011-09-12
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.
[100] 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
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
22

CA 02752558 2011-09-12
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.
[101] 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 steam16 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
23

CA 02752558 2011-09-12
the longitude system at 17. It is also possible to connect the parallel flow
and the
counter flow systems to each other where the discharge from the first system 3
or 17
still contains significant levels of liquids, possible in a slurry form, which
is fed into the
second system 18 or 7.
[102] 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.
[103] 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 5 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
24

CA 02752558 2011-09-12
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.
[104] 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.
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

CA 02752558 2011-09-12
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.
[105] 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 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.
[106] 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
26

CA 02752558 2011-09-12
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.
[107] 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 use, such as for
oil recovery
or for steam use in the chemical industry. The other portion 15 of the
produced steam
27

CA 02752558 2011-09-12
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.
[108] 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
described in FIGURE 3 where BLOCK 32 can 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
28

CA 02752558 2011-09-12
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
so it is constant. 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. 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.
[109] 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 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.
29

CA 02752558 2011-09-12
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 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. 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. 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.
[110] 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. 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
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

CA 02752558 2011-09-12
of a combined cycle. At least part of the produced dry superheated steam 36 is
used to
operate the SD-DCSG 30.
[111] 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.
[112] 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.
[113] FIGURE 6 is a schematic diagram of the present invention which includes
a SD-DCSG and an EOR 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 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
31

CA 02752558 2011-09-12
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
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.
[114] 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 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, 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
32

CA 02752558 2011-09-12
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.
[115] 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
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 B1, 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.
[116] 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
33

CA 02752558 2011-09-12
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 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.
[117] 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
34

CA 02752558 2011-09-12
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.
[118] 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

CA 02752558 2011-09-12
processing plant at 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 EOR 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.
[119] 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
36

CA 02752558 2011-09-12
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 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
37

CA 02752558 2011-09-12
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. 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. 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 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
38

CA 02752558 2011-09-12
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.
[120] FIGURE 7 is a schematic view of an integrated facility of the present
invention with a commercially available steam generation facility and for EOR
for heavy
oil production. The steam for EOR 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 EOR 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
39

CA 02752558 2011-09-12
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 EOR field facilities BLOCK 4, produces an
emulsion of
water and bitumen 3. In some EOR 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 between 1bar 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

CA 02752558 2011-09-12
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.
[121] 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
41

CA 02752558 2011-09-12
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 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.
[122] 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
42

CA 02752558 2011-09-12
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 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 EOR 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-
43

CA 02752558 2011-09-12
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 EOR 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.
[123] 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 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
44

CA 02752558 2011-09-12
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.
[124] 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 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

CA 02752558 2011-09-12
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 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 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.
[125] 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 /
46

CA 02752558 2011-09-12
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.
[126] 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
CO2. Steam
9 injected into a pressurized DCSG 15 at an elevated pressure. The DCSG design
can
be a horizontal sloped rotating reactor, however any other reactor that can
generate a
stream of 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 11B, the feed
water of the
MSF 45 is heated by direct contact heat exchange 25 (and not through an
indirect heat
exchanger). The feed water is injected into the up-flowing steam flow 12. The
steam
condenses because of heat exchange with the feed water 45. A non-direct heat
47

CA 02752558 2011-09-12
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 10 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.
[127] 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.
48

CA 02752558 2011-09-12
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.
[128] 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
49

CA 02752558 2011-09-12
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 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.
[129] FIGURE 13 is a schematic of the present invention for the generation of
hot water for oilsands mining extraction facilities, with Fine Tailing water
recycling. Block
1A includes a Prior Art commercial open mine oilsands plant. The plant
consists of
mining oilsands ore and mixing it with hot process water, typically in a
temperature
range of 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 1A. 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 produced steam 21 is
at a lower
temperature than steam 1 and contains additional water from the FT that was
converted

CA 02752558 2011-09-12
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 1A 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 Oi[sands plant 1A. 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.
[130] 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 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 1A. The
driving
steam 1 heat energy is transferred to the enclosure and used to evaporate the
FT 5.
Most of the liquid water in the FT is converted to steam. The remaining solids
4 are
removed in a solid / slurry stable form to use as a back-fill material which
can support
traffic. Steam 1 is generated by a standard boiler heating the condensate 1A
in a closed
cycle, allowing the use of high quality clean ASME BFW (not shown). The
produced
steam 21 is mixed with cold process water 8 from BLOCK 1A 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 1A. The amount of Non Condensable Gases (NCG) 2 is minimal.
Some
51

CA 02752558 2011-09-12
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.
[131] 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.
[132] 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 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
52

CA 02752558 2011-09-12
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.
[133] 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 H25 (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 flow
is fed into the
DCSG 1 or recycled and used as the process water (not shown). In the DCSG 1,
dry
53

CA 02752558 2011-09-12
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.
[134] 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 1 (See "Past, Present and Future Tailings, Tailing Experience at
Albiap
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
54

CA 02752558 2011-09-12
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 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

CA 02752558 2011-09-12
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.
[135] 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 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
56

CA 02752558 2011-09-12
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.
[136] 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. 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
57

CA 02752558 2011-09-12
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. 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.
58

CA 02752558 2011-09-12
[137] 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 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
59

CA 02752558 2011-09-12
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.
[138] 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 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.

CA 02752558 2011-09-12
[139] 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 11 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 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
61

CA 02752558 2011-09-12
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 EOR 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.
[140] The following are examples for heat and material balance simulations:
[141] 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 4.1ton/hour of steam 9 to gasify one ton/hour of
liquid water 7.
The following are the results of the simulation:
62

CA 02752558 2011-09-12
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
400.00 6159.21
350.00 8290.00
300.00 12990.00
250.00 34950.00
[142] 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:
Temperature of
System Pressure Driving Steam Flow
Saturated produced
(bar) (kg/hr)
Steam
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
63

CA 02752558 2011-09-12
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
[143] 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
1bar 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 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
T,C 25.00 450.00 120.61 120.61
P,atm 2.00 2.00 2.00 2.00
Vapor Fraction 0.00 1.00 0.00 1.00
Enthalpy, MJ -14885.08 -29133.36 -6692.49 -37325.62
Total Flow, kg/hr 1000.00 2311.54 414.73 2896.81
Water 600.00 2311.54 114.20 2797.34
Solids 300.00 0.00 '300.00 4.14E-17
Naptha 100.00 0.00 0.53 99.47
[144] 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.
64

CA 02752558 2011-09-12
[145] 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.
[146] 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
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
[147] 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,

CA 02752558 2011-09-12
15.1kg 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.
[148] 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.
[149] 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
Water, kg/hr 20.925 0.00 99.64 78.72 74.82 74.82
3.90 20.92
5102 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
[150] 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,
66

CA 02752558 2011-09-12
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
1, 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
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 water 9. The scrubbing
water 9
can include chemical to remove contaminates, like silica, from the produced
steam 4.
67

CA 02752558 2011-09-12
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
1, 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
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
[151] 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 10 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
68

CA 02752558 2011-09-12
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
1, C 200.00 271.89 271.89 271.89 271.88
271.88
Press., psig 600.00 600.00 600.00 600.00 600.00
600.00
Vapor Fraction 0.00 0.99 0.00 1.00 1.00 1.00
Enthalpy, kW -32.47 -87.32 -1.66 -85.64 -21.42 -
64.27
Total Flow, kg/hr 7.870 24.105 0.390 23.715 5.932 17.797
Water, kg/hr 7.320 23.500 0.000 23.500 5.879 17.636
Solids 0.390 0.390 0.390 0.000 0.000 0.000
Hydrocarbons 0.160 0.215 0.000 0.215 0.054 0.161
Flow No. 7 8 9 10 11 12
T, C 660.37 253.81 20.00 20.00 250.31
253.81
Press., psig 600.00 600.00 600.00 600.00 600.00
600.00
Vapor Fraction 1.00 1.00 0.00 0.00 0.00 0.00
Enthalpy, kW -53.87 -21.71 -1.32 -44.16 -65.87 -
1.04
Total Flow, kg/hr 15.927 5.927 0.300 10.000 15.927 0.305
Water, kg/hr 15.927 5.927 0.300 10.000 15.927 0.251
Solids 0.000 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.000 0.054
69

CA 02752558 2011-09-12
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 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
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
[152] 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

CA 02752558 2011-09-12
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
4.1kg/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,
kg/hr 20.930 40.518 1.050 39.468 18.552 20.920
Water, kg/hr 19.460 38.678 0.000 38.678 18.180
20.501
Solids 1.050 1.050 1.050 0.000 0.000
0.000
Hydrocarbons 0.420 0.791 0.000 0.791 0.372
0.419
Flow No. 7 8 9 11 12
T, C 493.17 253.81 20.00 253.81 253.81
Press., psig 600.00 600.00 600.00 600.00 600.00
71

CA 02752558 2011-09-12
Vapor Fraction 1.00 1.00 0.00 0.00 0.00
Enthalpy, kW -65.12 -68.38 -4.42 -77.12 -2.11
Total Flow,
kg/hr 18.671 18.671 1.000
18.671 0.881
Water, kg/hr 18.671 18.671 1.000 18.671 0.509
Solids 0.000 0.000 0.000 0.000 0.000
Hydrocarbons 0.000 0.000 0.000 0.000 0.372
[153] 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 5
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
72

CA 02752558 2011-09-12
N-Pentane 0.32 1.05 0.00 1.05 0.73 0.73
N-Hexane 0.14 0.45 0.00 0.45 0.31 0.31
Flow Number 7 8 9 10 11
T, C 534.94 99.73 20.00 80.11 80.11
Press., atm 1.00 1.00 1.00 1.00 1.00
Vapor Fraction 1.00 1.00 0.00 1.00 0.00
Enthalpy, kW -161.88 -74.61 -821.39 -0.61 -895.39
Total Flow,
kg/hr 48.89 20.95 186.00 0.51 206.44
Water, kg/hr 46.79 20.05 186.00 0.10 205.95
Solids 0.00 0.00 0.00 0.00 0.00
N-Butane 1.05 0.45 0.00 0.26 0.18
N-Pentane 0.73 0.31 0.00 0.12 0.20
N-Hexane 0.31 0.13 0.00 0.03 0.11
[154] 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
73

CA 02752558 2011-09-12
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
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
[155] 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 600ps1 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
74

CA 02752558 2011-09-12
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
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
[156] 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 12KVV. 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

CA 02752558 2011-09-12
[157] 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 600ps1 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.
76

A single figure which represents the drawing illustrating the invention.

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BETSER-ZILEVITCH, MAOZ
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