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Patent 2751186 Summary

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(12) Patent: (11) CA 2751186
(54) English Title: ZERO EMISSION STEAM GENERATION PROCESS
(54) French Title: PROCEDE DE PRODUCTION DE VAPEUR A EMISSIONS NULLES
Status: Granted
Bibliographic Data
(51) International Patent Classification (IPC):
  • F22B 1/00 (2006.01)
  • C02F 1/04 (2006.01)
  • E21B 43/24 (2006.01)
  • F22B 37/26 (2006.01)
(72) Inventors :
  • BUNIO, GARY L. (Canada)
  • GATES, IAN D. (Canada)
  • SUDLOW, PAUL (Canada)
  • ANDERSON, ROGER E. (United States of America)
  • PROPP, MURRAY E. (Canada)
(73) Owners :
  • PAXTON CORPORATION (Canada)
  • CLEAN ENERGY SYSTEMS, INC. (United States of America)
  • PARAMOUNT RESOURCES LTD. (Canada)
(71) Applicants :
  • PAXTON CORPORATION (Canada)
  • CLEAN ENERGY SYSTEMS, INC. (United States of America)
  • PARAMOUNT RESOURCES LTD. (Canada)
(74) Agent: NORTON ROSE FULBRIGHT CANADA LLP/S.E.N.C.R.L., S.R.L.
(74) Associate agent:
(45) Issued: 2013-06-18
(22) Filed Date: 2011-08-31
(41) Open to Public Inspection: 2012-06-23
Examination requested: 2012-03-30
Availability of licence: N/A
(25) Language of filing: English

Patent Cooperation Treaty (PCT): No

(30) Application Priority Data:
Application No. Country/Territory Date
61/426,743 United States of America 2010-12-23

Abstracts

English Abstract

This invention provides a new process to generate steam directly from untreated water produced simultaneously with thermally recovered crude oil, and to inject the steam and combustion products into a hydrocarbon reservoir to recover hydrocarbons and to sequester a portion of the carbon dioxide produced during the creation of steam. The invention removes the ongoing additional water requirements for thermal oil recovery and the need for surface treating of produced water for re-use, yielding improved process efficiencies, reduced environmental impact, and improved economic value.


French Abstract

Cette invention fournit un nouveau processus pour générer de la vapeur directement ) partir deau non traitée produite de manière simultanée avec le pétrole brut extrait thermiquement, et pour injecter la vapeur et les produits de combustion dans un réservoir dhydrocarbure afin de récupérer lhydrocarbure et disoler une partie du dioxyde de carbone produit au cours de la création de la vapeur. Linvention permet de ne pas tenir compte des conditions deau supplémentaire pour la récupération dhuile thermique ainsi que de la nécessité de traiter la surface de leau produite pour être réutilisée, et génère une efficacité du processus, un impact réduit sur lenvironnement et de meilleures valeurs économiques.

Claims

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


16
Claims

1. A steam processing system comprising:
a) an oxy-fuel steam generator having an inlet for fluids, said generator
adding
heat directly to inlet fluids by intimately combining the combustion fuels,
oxygen and a water feed in a reaction chamber in sufficient proportions, for a

substantially complete combustion; this system providing a steam mixture
with carbon dioxide and traces of impurities in the outlet; and
b) a steam separator, utilizing advanced inert metallurgy, controlling the
quality
of the steam mixture; wherein the resulting steam mixture is used as an
injectant in a thermal oil process.
2. A method of using the steam processing system of claim 1, said method
comprising:
a) Injecting fuel and oxygen together into the reaction chamber
b) Igniting the mixture,
c) Passing feed water through the combustion gases;
d) Adding additional water downstream of the ignited mixture until a desired
carbon dioxide and steam mixture is attained; and
e) Removing entrained impurities downstream, prior to the injection of a 100%
quality steam and carbon dioxide mixture.

3. The method of claim 2, wherein the feed water comprises untreated
subterranean
water.

4. The method of claim 3, wherein said untreated subterranean water comprises
unlimited suspended solids greater than 4,000 ppm hardness.

5. The method of claim 3, wherein the mixture generated for injection consists
largely of steam and carbon dioxide;
the mixture being generated by:

17
a) injecting fuel and oxygen together into a reaction chamber at a pressure
substantially between 690 and 17,800 kPa;
b) igniting the mixture;
c) passing produced water through the combustion gases;
d) adding additional produced water downstream of the ignited mixture until a
desired carbon dioxide, vapour steam and liquid water mixture is attained; and
e) removing any liquid salt water or brine downstream.

6. The method of claim 2 wherein lower quality steam with less than 100%
saturation and carbon dioxide is generated by said steam processing system.

7. The method of claim 2 wherein the fuel is selected from the group
consisting of:
methane, oil, heavy oil, bitumen, emulsions, mixtures thereof and similar
fluid materials
that undergo combustion with oxygen.

8. The method of claim 2 further comprising production of water condensed
from
injected steam, subterranean water and associated oil from the thermal oil
recovery
process through an injection well, an adjacent well, or both.

9. The method of claim 2 further comprising the use of some liquid blowdown
water
from said steam separator as process feed water, and disposing of any balance
of liquid
blowdown water.

10. The method of claim 9 further comprising the removal of solids from liquid

blowdown prior to sequestration or re-use as feed water.

11. The method of claim 2, further comprising varying the carbon dioxide in
said
mixture from 1 to 50 volume percent of the injectant stream through the use of
other fuels
and / or carbon dioxide recirculation.

18
12. The method of claim 11, further comprising altering carbon dioxide in the
injectant stream used to increase thermal oil recovery from a reservoir where
the carbon
dioxide is ramped up from 1 to 50 volume percent as the recovery process
evolves or
ramped down from 50 to 1 volume percent as the recovery process evolves.

13. The method of claim 2, further comprising operating a reservoir and
surface
facilities to capture the majority of produced carbon dioxide to re-inject the
carbon
dioxide back into the reservoir.

14. The method of claim 2, further comprising locating steam processing
systems
remotely at well sites.

15. The method of claim 2, further comprising adding light hydrocarbons or
other
solvents to the mixture of steam and carbon dioxide downstream of said steam
separator
to act as a further solvent.

16. The method of claim 15 where the solvent is selected from the group
consisting of
propane, butane, pentane, hexane, natural gas condensates, diluent, naphtha
and
combinations thereof.

17. The method of claim 2, wherein partial combustion is taking place to
produce a
synthesized gas that is delivered to a thermal oil well for injection in a
thermal oil
recovery process accomplished through partial oxidation of the fuel which,
together with
pyrolysis and aquathermolysis, produces a synthesized gas consisting of water,
hydrogen,
carbon dioxide, and carbon monoxide, which gas is injected into the oil
formation to
enable oil recovery and partial upgrading when the injected gas is at
sufficient
temperatures to enable in situ gasification of the oil.
18. The method of claim 17 wherein said sufficient temperatures are above
about
300°C.

19
19. A steam processing system comprising:
an oxy-fuel steam generator having an inlet for fluids including combustion
fuels, oxygen
and feed water including a percentage of dirty returned process water having
substantially
over 4,000 ppm suspended solids , said generator adding heat directly to inlet
fluids by
intimately combining the combustion fuels, oxygen and feed water in a reaction
chamber
in sufficient proportions at a pressure:
a) substantially between 690 and 17,800 kPa,
b) for Steam Assisted Gravity Drainage (SAGD) substantially between 500 to
5000 kPa,
c) for Cyclic Steam Stimulation (CSS) substantially at or above the fracture
pressure of a reservoir
for substantially complete combustion; this system providing a steam mixture
with
carbon dioxide and traces of impurities in the outlet; and
a steam separator, constructed utilizing advanced inert metallurgy, and
controlling the
quality of the steam mixture; wherein the resulting steam mixture is used as
an injectant
in a thermal oil process.

20. A method of using the steam processing system of claim 19, said method
comprising:
a) Injecting fuel and oxygen together into the reaction chamber
b) Igniting the mixture,
c) Passing feed water through the combustion gases;
d) Adding additional water downstream of the ignited mixture until a desired
carbon dioxide and steam mixture is attained; and
e) Removing entrained impurities downstream, prior to the injection of a
substantially pure quality steam and carbon dioxide mixture in a thermal oil
process.
21. The method of claim 20, wherein the feed water and additional water
comprises a
percentage of dirty process return water condensed from steam, subterranean
water and
associated oil from said thermal oil recovery process.

20
22. The method of claim 21, wherein said water comprises unlimited suspended
solids.

23. The method of claim 22 wherein the unlimited suspended solids are greater
than
4,000 ppm.

24. The method of claim 22 wherein said water further comprises hardness and
any
other components, that is co-produced with oil production.

25. The method of claim 20, wherein the mixture generated for injection
consists
largely of steam and carbon dioxide for use as an injectant in a thermal oil
recovery
process;
the mixture being generated by:
a) injecting fuel and oxygen together into a reaction chamber and igniting the

mixture;
b) passing produced water through the combustion gases;
c) adding additional produced water downstream of the ignited mixture until a
desired carbon dioxide, vapour steam and liquid water mixture is attained; and
d) removing any liquid salt water or brine downstream, prior to the injection
of a
substantially pure quality steam and carbon dioxide mixture in a thermal oil
recovery process.

26. The method of claim 20 wherein a lower quality steam of less than 100%
saturation and carbon dioxide is generated by said steam processing system.

27. The method of claim 20 wherein the fuel is selected from the group
consisting of:
methane, oil, heavy oil, bitumen, emulsions, mixtures thereof and similar
fluid materials
that undergo combustion with oxygen.

21
28. The method of claim 20 further comprising production of water condensed
from
injected steam and associated oil from the thermal oil recovery process
through an
injection well, an adjacent well, or both.

29. The method of claim 20 further comprising the use of some liquid blowdown
water from said steam separator as process feed water, and disposing of any
balance of
liquid blowdown water.

30. The method of claim 29 further comprising the removal of solids from
liquid
blowdown prior to sequestration or re-use as feed water.

31. The method of claim 20, further comprising varying the carbon dioxide in
said
mixture from 1 to 50 volume percent of the injectant stream through the use of
other fuels
and / or carbon dioxide recirculation.

32. The method of claim 31, further comprising altering carbon dioxide in the
injectant stream used to increase thermal oil recovery from a reservoir where
the carbon
dioxide is ramped up from 1 to 50 volume percent as the recovery process
evolves or
ramped down from 50 to 1 volume percent as the recovery process evolves.

33. The method of claim 20, further comprising operating a reservoir and
surface
facilities to capture the majority of produced carbon dioxide to re-inject the
carbon
dioxide back into the reservoir.
34. The method of claim 20. further comprising a modular transportable steam
processing system and locating said system remotely at well sites.

35. The method of claim 20, further comprising adding light hydrocarbons or
other
substances that can act as a further solvent to the mixture of steam and
carbon dioxide
downstream of said steam separator to act as a further solvent.

22
36. The method of claim 35 where the solvent is selected from the group
consisting of
propane, butane, pentane, hexane, natural gas condensates, diluents, naphtha
and
combinations thereof.

37. The method of claim 20, wherein partial combustion is taking place to
produce a
synthesized gas that is delivered to a thermal oil well for injection in a
thermal oil
recovery process accomplished through the partial oxidation of the fuel which,
together
with pyrolysis and aquathermolysis, produce a synthesized gas consisting of
mixtures of
water, hydrogen, carbon dioxide, and carbon monoxide injected into the oil
formation to
enable oil recovery and partial upgrading when the injected gas is at
sufficient
temperatures to enable in situ gasification of the oil.
38. The method of claim 37 wherein said sufficient temperatures are above
about
300°C .

39. The method of claim 4 wherein the mixture generated for injection consists

largely of steam and carbon dioxide for use as an injectant in a thermal oil
recovery
process.

40. The method of claim 39 wherein said thermal oil recovery process is
selected
from the group consisting of Steam Assisted Gravity Drainage (SAGD), Cyclic
Steam
Stimulation (CSS), Steam Flooding, and thermal recovery processes comprising
in situ
combustion.

41. The method of claim 25, wherein the mixture generated for injection
consists
largely of steam and carbon dioxide for use as an injectant in a thermal oil
recovery
process.
42. The method of claim 41 wherein said thermal oil recovery process is
selected
from the group consisting of Steam Assisted Gravity Drainage (SAGD), Cyclic
Steam
Stimulation (CSS), Steam Flooding, and thermal recovery processes comprising
in situ
combustion.

Description

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


CA 02751186 2011-08-31


TITLE OF THE INVENTION

Zero Emission Steam Generation Process

FIELD OF THE INVENTION

The current invention pertains to an area of generating of steam for the
thermal recovery of oil
and bitumen from subsurface hydrocarbon reservoirs. Specifically, to the area
of using an
oxygen fuel combustor as a steam generator.

BACKGROUND OF THE INVENTION

Thermal oil recovery projects, including but not limited to Steam Assisted
Gravity Drainage
(SAGD), Cyclic Steam Stimulation (CSS), or Steam Flooding, or recovery
processes that
potentially start with steam injection (e.g. in situ combustion) utilize large
amounts of water in
the form of steam, to carry heat energy underground to mobilize the oil, heavy
oil, or bitumen.
This water, typically in a ratio of three or higher parts water to one part
oil, is transported back to
the surface with the oil. Previous processes have required extensive water
treatment and
handling to clean the water prior to it being re-used as boiler feed water.
For example, water
treatment can involve one or more of gravity segregation, water softening,
filtration, de-salting,
de-oiling, and chemical treatments.

Water treatment is an essential part of any process since the introduction of
the "dirty" water into
the boiler would hold back or even shut down the process due to scaling of the
boiler, and other
process disrupting events. The build-up of the impurities in the boiler
requires cleaning up of the
boiler, constructing a subsidiary boiler for the maintenance periods to clean
the main boiler and
so on. Dealing with the impurities result in increased capital, maintenance,
operating cost, and
environmental impact. Usually in a traditional thermal oil recovery system the
water treatment
process, accounts for up to 50 % of the operating costs.

Therefore, there is a need to remove the reliance of the oil production
process on water treatment
and cleaning operations.

Further there is a need for a process to utilize poor quality or "dirty"
water, or a water that has
not undergone any softening and treatment, to create steam for thermal oil
recovery.

CA 02751186 2011-08-31

2

Moreover, all thermal recovery projects have ongoing water requirements to
make up water
losses and water treating blow down. These losses can be up to 20% per
operating day. There is
a need to reduce or eliminate these additional water requirements.

Further there is an environmental requirement to reduce the release of
combustion by-products
such as nitrous oxide components and carbon oxide components into the
atmosphere.

Traditionally heating/cooling processes take place in heat exchanger vessels
and devices, which
have one common deficiency: all those vessels and devices used in all
industries maintain a
separation between reactive substances and the targets of heating or cooling.
For example, all
industrial boilers either use fire tubes or single or multiple pass boiler
tubes, segregating water
(to be heated) from the heat source (combustion zone). Similarly, glycol or
areal coolers
separate the cooling media from the process fluid. This separation reduces the
efficiency of the
heaters and coolers substantially.

There is an opportunity to gain more efficiency and process flexibility by
combining the
combustion process and the feed-water intimately within a single process
vessel. Commingling
the combustion gases with the feed-water, removes all heat transfer surfaces
and leads to higher
thermal efficiency than a typical drum boiler or once-through steam generator,
since no heat is
lost with the stack gases. The examples of such a vessel taught in US Patents
5,680,764 and
6,170,624 among others and is referred to as "oxy-fuel steam generator" in the
current
application.

Thermal oil projects use large amounts of energy, and emit carbon dioxide to
the atmosphere as a
by-product. Canadian Patent 2,576,896 by Kresnyak and Bunio, among others,
illustrates the
use of oxygen burning technology to create a gas emission stream consisting
predominantly of
carbon dioxide, which can then be sequestered or used for enhanced oil or gas
recovery.
Canadian Patent Application 2,619,557 by Turta et al., among others,
illustrates methods of
using of carbon dioxide for enhancing oil and gas recovery. In all those cases
the methods of
capturing carbon dioxide for use in enhanced hydrocarbon recovery are
complicated and capital
intensive.

It is well known in the art of enhanced oil recovery that carbon dioxide can
act as a solvent and
swelling agent, increasing oil recovery in some situations when injected into
the oil formation.

CA 02751186 2011-08-31

3
In thermal recovery however, free gas in a reservoir may lower the in-situ
reservoir temperature,
which in turn will reduce oil recovery. The right mixture of carbon dioxide
and steam that
enables at least the same level of recovery while sequestering the greenhouse
gas is required.

Therefore, there is a need for a process for generating high quality steam,
that is, steam with a
majority of its mass in vapour form, from the produced water without treating
this water
beforehand. There is a need for a new method of capturing carbon dioxide for
use in thermal
hydrocarbon recovery and sequestration. Finally there is a need to reduce the
reliance on the
make up water for the thermal oil recovery processes.

Further and other objects of the invention will become apparent to one skilled
in the art when
considering the following summary of the invention and the more detailed
description of the
preferred embodiments illustrated herein.

SUMMARY OF THE INVENTION

There is provided a new thermal process for generation of a gaseous mixture of
steam and
carbon dioxide, by the provision of an oxy-fuel steam generator relying on
untreated water,
which obviates the requirement for water handling and treatment prior to steam
generation.

Specifically, the process uses the apparatus, designed as a gas generator, as
a new concept of the
process vessel to use subterranean waters, which are co-produced with oil,
directly for steam
without softening or treating prior to boiling. Thermal recovery includes, but
not limited to,
Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), Steam
Flooding, or
combined steam-additive processes where the additive can be one or more of non-
condensable
gas, solvent, or surfactant. In addition the process captures all combustion
gases produced and
injects steam and combustion gasses underground simultaneously, removing the
ongoing
requirement for make up water in thermal oil recovery.

The alternative gas generator was developed initially to create a stream of
superheated steam and
carbon dioxide for use in electrical power generation, and is illustrated in
US Patents 5,680,764
and 6,170,624 among others. This alternative gas generator is a new generation
of the process
vessel that intimately commingles process fluids with heat or cooling media.
In all other process
vessels, the heat source or sink is physically separated by a barrier such as
a metal tube wall
across which heat transfer occurs. For example, all conventional boilers use
either fire tubes or

CA 02751186 2011-08-31

4
boiler (water) tubes to maintain a separation of combustion gases and feed-
water fluids. In the
original embodiment, the gas generator used demineralized water, natural gas
and oxygen to
create a relatively pure steam carbon dioxide mixture to power an electric
turbine. At the tail
end of the process, the steam was condensed for re-use and the carbon dioxide
sequestered
underground. The Gas Generator which can be used as oxy-fuel steam generator
is manufactured
by "Clean Energy Systems".

This invention expands the previous Patent Application WO 2010/101647 by
Anderson et al,
which demonstrated an initial embodiment of the gas generator as a replacement
of a traditional
boiler in a Steam Assisted Gravity Drainage (SAGD) operation. In the original
disclosure, 100%
quality steam and carbon dioxide are produced, with trace impurities being
removed by a salt
separator prior to use in a SAGD process.

This invention enables the use of the oxygen-fuel steam generator to use
untreated oil field
produced water to produce 100% quality steam for use in thermal oil recovery.
This is
accomplished by changing generator operating conditions, creating less than
100% quality steam
in the steam generator, and the addition of a steam separator to remove
resulting brine. Unlike
all other steam generation process, all of which require water softening above
approximately
5000 ppm suspended solids in boiler feed-water, this invention requires no
input water
conditioning at any level of suspended solids in the water.

In this application the terms "dirty water", "brackish water" and "untreated
water" refer to
liquids with high content of impurities approximately 500 to 20,000 ppm or
higher. While the
impurities may constitute salts, oils residuals and other organic and non-
organic contaminants.
The source of the water can be the local ground water, underground water or
the water extracted
from the hydrocarbons recovery process. In the preferred embodiment, the dirty
water is not
treated prior to introduction into the steam generator.

This invention also expands uses to all thermal oil recovery applications and
discusses other
substances for co-injection, which could further improve thermal oil recovery.

According to a preferred embodiment of the invention, there is provided a
steam processing
system having:

CA 02751186 2011-08-31

5
a) an oxy-fiiel steam generator having an inlet for fluids, a reaction
chamber
and an outlet. This generator adds heat directly to inlet fluids by intimately

combining the combustion fuels, oxygen and water feed in the reaction
chamber in sufficient proportions, for a substantially complete combustion.
This system provides a steam mixture with carbon dioxide and traces of
impurities in the outlet.
b) a steam separator controlling the quality of the steam mixture.

Further, the resulting steam mixture is used as an injectant in a thermal oil
process.

According to another preferred aspect of the invention there is provided a
steam processing
system having:
an oxy-fiiel steam generator with an inlet for fluids including combustion
fuels, oxygen and
water including a percentage of dirty returned process water having
substantially over 4,000
p.p.m. suspended solids. Said generator adding heat directly to inlet fluids
by intimately
combining the combustion fuels, oxygen and water feed in a reaction chamber in
sufficient
proportions at the operating pressure substantially:
a) generally between 690 and 17,800kPa,
b) for SAGD between 500 to 5000 kPa and preferably between 1000 and 3000 kPa.
c) for CSS at or above the fracture pressure of the reservoir
for a substantially complete combustion. This system providing a steam mixture
with carbon
dioxide and traces of impurities in the outlet. The system also has a steam
separator, constructed
utilizing advanced inert metallurgy, and controlling the quality of the steam
mixture; wherein
the resulting steam mixture is used as an injectant in a thermal oil process.

According to another aspect of the invention, there is provided a method of
using the steam
processing system having the following steps:

a) Injecting fuel and oxygen together into a combustion chamber / flame unit;
b) Igniting the mixture/or keeping the mixture ignited;
c) Passing feed water through the combustion gases;
d) Adding additional water downstream of the flame until a desired carbon
dioxide and steam mixture is attained;
e) Removing entrained impurities downstream, prior to the injection of a 100%

quality steam and carbon dioxide mixture.

CA 02751186 2011-08-31

6

According to a preferred embodiment, the feed water includes untreated
subterranean water,
which is co-produced with oil production. The ability to use this untreated
produced water will
result in following advantages:

It will remove the ongoing requirement for additional water into a thermal oil

recovery process such as, but not limited to, Steam Assisted Gravity Drainage
(SAGD), Cyclic Steam Stimulation (CSS), or Steam Flooding, or other recovery
processes that start with steam injection e.g. in situ combustion. By
capturing the
water of combustion, once the production process is stable, no further water
will
be required.

It will increase the thermal efficiency of the process. By capturing heat lost
to
stack emissions and further piping losses, thermal efficiencies can increase
by
more than 10%.

It will reduce thermal oil recovery process capital and operating costs by up
to
50%, through the complete removal of water treatment equipment.

According to yet another aspect of the invention there is provided a method
for using a steam
processing system wherein the mixture generated for injection consists largely
of steam and
carbon dioxide. This mixture being used as an injectant in a thermal oil
process such as, but not
limited to, Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation
(CSS), Steam
Flooding, or other recovery processes that start with steam injection e.g. in
situ combustion.
This mixture being generated by:

a) injecting fuel and oxygen together into a reaction chamber at a pressure
between 690 and 17,800 kPa;
b) igniting the mixture of the combustion gases / or maintaining the ignition
c) passing produced water through the combustion gases;
d) adding additional produced water downstream of the flame until a desired
carbon dioxide, vapor steam and liquid water mixture are attained.
e) removing any liquid salt water or brine downstream, prior to the injection
of
a substantially pure quality steam and carbon dioxide mixture.

CA 02751186 2011-08-31

7
Ultimately, the method provided above might result in a lower quality steam
(<100% saturation)
and carbon dioxide generated by the steam processing system.

Preferably, the fuel for the process is selected from: methane, oil, heavy
oil, bitumen, emulsions,
or mixtures thereof or similar fluid materials that undergo combustion with
oxygen.

The method may further result in production of water condensed from injected
steam and
associated oil from the thermal recovery process through the injection well, a
production well, an
adjacent well, or combination of those.

According to yet another aspect of the invention the method may further
utilize some liquid blow
down water from the steam separator as process feed water, and dispose of the
balance of liquid
blow down water. Preferably, the method further comprises the removal of
solids from liquid
blow down prior to sequestration or re-use as feed water.

The method may optionally have variations such as:

= Varying the fraction of carbon dioxide in the injectant stream through the
use
of other fuels and / or carbon dioxide recirculation.
= Altering carbon dioxide in the injectant stream used to increase thermal
oil
recovery from a reservoir.
= Adding light hydrocarbons or other substances to the mixture of steam and
carbon dioxide downstream of the steam separator to act as a further solvent.

The steam processing system may further include a reservoir and surface
facilities to capture the
majority of produced carbon dioxide to re-inject the carbon dioxide back into
the reservoir.

According to yet another aspect of the invention the steam processing systems
utilized by the
methods listed above may be located remotely at well sites, in contrast to the
standard practice of
building a central plant.

Ultimately, the method may be conducted in the way when a partial combustion
is taking place
to produce a synthesis gas that is delivered to a thermal oil well for
injection in a thermal oil
recovery process.

CA 02751186 2011-08-31

8
BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is a schematic flow diagram according to the preferred embodiment of
the invention.
Figure 2A displays a pressure-temperature-solubility-viscosity map for
mixtures of carbon
dioxide and bitumen and Figure 28 is an example of the viscosity of mixtures
of hexane and
bitumen.

Figure 3 is an example of a material flow diagram in the preferred embodiment
of the invention.

Figure 4 is a schematic illustration of a conventional thermal oil recovery
process.

Figures 5 and 6 are side and front schematic views of Steam Assisted Gravity
Drainage thermal
recovery process.

Figure 7 is a schematic view of the Cyclic Steam Stimulation thermal recovery
process.

Figure 8 is a schematic view of Steam Flood thermal recovery process.

CA 02751186 2011-08-31

9

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Several deficiencies in current thermal oil recovery schemes known in the art
are addressed in
the current invention:

First, thermal recovery schemes use vast amounts of water. While modern
schemes meet up to
95% of their water requirements through the re-use of produced water, some
make-up water is
still usually required. According to the current invention, the water is
created as a byproduct of
combustion, when fuel, e.g. natural gas, and oxygen are combined. This water
is captured and
added to the steam available for injection. This means that once the system is
operating at the
steady state, make-up water is no longer required. In most cases, it is
expected that the process
will require that a small amount of blow down water is disposed of in deep
subsurface
formations.

Second, thermal recovery schemes are noted to produce carbon dioxide
emissions, a greenhouse
gas. In this embodiment, all the carbon dioxide produced during steam
generation is injected
down hole. Once down hole, the majority of the carbon dioxide is retained
there through
dissolution in the connate water present in the reservoir. Some fraction of
the carbon dioxide will
also dissolve in non-produced oil in the reservoir. Potentially, some other
fraction of the carbon
dioxide can be chemically converted to solid form through mineralization
reactions. In addition,
the majority of carbon dioxide entrained in produced fluids will be captured
in the surface plant,
flowed through the steam generator with associated fuel gas, and injected once
again. When a
well is finally depleted of a resource, a significant mass of carbon dioxide
will be permanently
left behind, that is, sequestered, in the reservoir.

Third, the capital expenditure and equipment required to re-use produced water
(produced with
oil from the reservoir) in conventional thermal oil recovery schemes are
immense, approaching
one-half of the total capital and operating expenditure required. Because this
embodiment
removes the requirement for water treatment, capital costs are significantly
reduced, and the
environmental footprint is diminished. With the new technology, given the
elimination of water
treatment and handling equipment and operation, capital and operating costs
will be reduced by
up to 50% from that of a traditional facility system.

CA 02751186 2011-08-31

10
Fourth, the carbon dioxide that is simultaneously injected with the steam may
have solvent
properties when used in specific reservoirs, and specific fractions. By tuning
the carbon dioxide
mass fraction the impact on oil recovery can be maximized, from no incremental
impact to up to
25% additional recovery.

In the first embodiment of this new process, shown in Figure 1, the oxy-fuel
steam generator
directly mixes fuel such as natural gas, oxygen and feed water to generate a
steam, liquid water
and carbon dioxide mixture. The fuel and the Oxygen are mixed and burned in
the reaction
chamber which also known as a combustion chamber of the flaming unit. The feed
water is
added directly to this reaction chamber into the mixture of the combustion
gases while part of the
impurities in the water takes part in the burning process while generating
steam mixture.

The water in the inlet of the generator containing anywhere from 500 to 20,000
ppm dissolved
solids. This is a substantial improvement, since the current industrial
boilers have an upper limit
to dissolved solids of up to 5,000 ppm. The steam generator output quality
will be altered from
100% to under 60%, depending on the suspended solids present in the input
water. Steam
generator metallurgy will be altered to ensure corrosion will not occur in the
brief contact within
the steam generator. In the preferred embodiment, the carbon dioxide fraction
in the steam is
between 7% and 15% by mass. Carbon dioxide acts both as an agent to reduce the
viscosity of
oil and as a swelling agent. While oil swells, it comes out of tight pores,
and since it is more
mobile (viscosity is lower), it flows more readily to the production well.
Figure 1 further
illustrates the use of the generated steam in several thermal oil processes.
Those processes
illustrated in further details in Figures 4 to 7. In Figure 1 there are
illustrated injection wells,
receiving the steam and the production wells, from which oil and water are
extracted.
Consequently, after the separation of the oil from the produced water, in the
oil treatment unit,
the produced water is fed directly into the steam processing system without
any additional
treatment.

One consequence of having direct combustion of fuel with water for steam
generation is that the
other main product of combustion is carbon dioxide. To separate steam from
carbon dioxide is
technically difficult (while preserving steam quality) and expensive. Thus,
the carbon dioxide is
injected with the steam and has impact on the process as a solvent in the oil.
(which lowers oil
viscosity and causes oil swelling). The diagram displays the viscosity of oil-
carbon mixtures
versus pressure and temperature. The temperature of the oil is set by the
temperature of the
steam and the carbon dioxide solubility and consequent viscosity of the oil is
set by both the

CA 02751186 2011-08-31

11
temperature and partial pressure of the carbon dioxide in the vapour chamber
in the recovery
process. Thus, an additional benefit of the system is the capability to inject
steam plus carbon
dioxide (a solvent and oil swelling agent) into the reservoir. Figure 2A
displays this. Further
addition of heavier solvents into the steam-carbon dioxide mixture can be
made. This addition
lowers the oil phase viscosity even lower than that with steam-alone and steam-
carbon dioxide
injection thus yielding even higher oil rates.

The fraction of carbon dioxide can be varied to achieve the optimum economic
recovery from
the reservoir by changing the volume percent of carbon dioxide in the
injectant stream through
the use of other fuels and / or carbon dioxide recirculation. Figure 2A
displays a pressure-
temperature-solubility-viscosity map for mixtures of carbon dioxide and
bitumen. While "x"
denotes the mole fraction of the carbon dioxide dissolved in the oil phase.
The solubility
presented is the solubility of carbon dioxide in the bitumen at a given
temperature and partial
pressure of carbon dioxide in the injectant stream. The isoviscosity lines
reveal that the viscosity
of the carbon dioxide and bitumen versus temperature and pressure can be
altered by varying the
solubility, in other words the temperature and partial pressure, of the carbon
dioxide in the
injectant stream. The partial pressure of the carbon dioxide in the injectant
stream is set by the
total injection pressure and the volume percent of carbon dioxide in the
injectant stream. Also,
the temperature of the injectant stream is set by the partial pressure of the
steam in the stream.
Thus, there is a competition between the steam temperature (higher temperature
means lower oil
viscosity) and carbon dioxide partial pressure (higher carbon dioxide content
means more
dissolved in oil which means lower oil viscosity). For bitumen production
processes such as
SAGD, the production rate is mainly proportional to the oil mobility (ratio of
oil effective
permeability and oil viscosity) thus the optimum reduction of the oil
viscosity can be realized by
using varying amounts of carbon dioxide in the injectant stream. Other
solvents beyond carbon
dioxide can be added to the injectant stream to further reduce the oil
viscosity. For example,
propane, butane, pentane, hexane, natural gas condensates, diluent, naphtha
and combinations
can be added to the injectant stream to reduce the oil viscosity below that
achieved by dissolving
carbon dioxide in the oil phase. By example, Figure 2B displays viscosity of a
mixture of
hexane and bitumen versus volume percent of hexane. Solvents such as propane,
butane,
pentane, hexane, natural gas condensates, diluent, naphtha and combinations
can be expensive
thus adding carbon dioxide to the injectant will reduce the overall cost of
the solvent package
(solvent plus carbon dioxide) added to the injected steam.

CA 02751186 2013-03-01

12
Figure 3 shows an example of the mass balance of the system of the steam
processing unit
comprising the oxy-fuel steam generation of Figure 1.

Downstream of the steam generator, a high-pressure steam separator removes the
liquid water
fraction from the 100% to 60% steam & carbon dioxide mixture (blow-down
water). The
metallic composition of the steam separator is critical to the success of the
new process.
Previous steam separators used with conventional or direct-fired boilers
limited the brine
composition because of corrosion and erosion issues. In this embodiment the
separator is
constructed of an extremely inert metal, such as Hastelloy or lnconelTM,
which allow the liquid
water to be saturated with extremely corrosive salts, metals and combustion
products. This water
may be re-injected directly for steam generation, unlike traditional boilers
where this blow down
water must be disposed of and make-up water must be added. In this embodiment
only water
superfluous to steam requirements is disposed of through injection. In all
cases the water is re-
injected deep underground along with all corrosive and combustion products,
some of which in
traditional thermal oil recovery processes is released to the atmosphere.

From the high-pressure separator, the steam carbon dioxide mixture flows to
one or more
injection wells to deliver it to the underground reservoir. The mixture of
steam and carbon
dioxide may be delivered at any pressure between 690 to 17,800 kPa (100 and
2,000 psi) and at
any steam quality between 65 and 100%, dependent only on retaining enough
liquid water to
suspend the solids entrained in the produced water input. Recommend range of
conditions of
operation between 500 kPa and 12,000 kPa while the preferred range for SAGD is
500 to 5000
kPa and most preferred is between 1000 and 3000 kPa. Preferred operational
range for CSS is at
or above the fracture pressure of the reservoir. With regards to steam quality
¨ the preferred
value is 100% (but in practice it is >90% for SAGD and ¨65% for CSS).

After sufficient residence time in the reservoir to allow for heat transfer,
the condensed steam ¨
water ¨ is produced backup production well. The injection well may also act as
a production
well alternatively an adjacent well or wells may be used for oil production.
The water and oil are
then separated in conventional oil field separation equipment, and the "dirty"
produced water is
fed untreated to the inlet of the oxy-fuel steam generator.

The oxy-fuel combustor which may be used as an oxy-fuel steam generator is
produced, for
example, by Clean Energy Systems. The oxygen for the process can be provided
by any means

CA 02751186 2011-08-31

13
known in the art such as cryogenic methods, pressure swing from the air
techniques or any other
air treatment devices.

The additional benefits of the new system are as following: The new oxy-fuel
combustor is small
and modular and can be easily moved around the field whereas old ones were
very large and are
never or rarely moved. Further, given nature of steam generation in new
generator (direct
contact of combustion front and water), heat transfer is much more efficient.
In the prior art,
combustion heats pipe which heats water to steam within. In the new one, there
are no pipes,
therefore no pipe heat losses occurs reducing heat transmission
inefficiencies. The steam quality
from new generator can be high or close to 100%, since impurities are driven
convectively
through system. In old generator, the steam was often generated at lower
quality to prevent build
up of solids in the pipes. Since there are no pipes in the new design, the
build-up of solids is not
an issue.

In a second embodiment, the process uses the steam generator and separator
combinations
directly at the remote well site (at satellite locations in the oil field)
instead of conventional
practice where they are located at a central plant. Fuel (e.g. natural gas),
oxygen, and produced
water are piped to the remote satellites where the steam generators can be
sited. In this
embodiment, the location is no longer tied to an extensive and expensive water
treatment
apparatus. The suggested capacity for the remote oxy-fuel steam generator is
about 20 MW.
However, the sizes and capacities of those generators may vary according to
the requirements of
the industry.

In a third embodiment of the invention, the oxy-fuel steam generator can use
partially enriched
air, with up to 10% remaining nitrogen content, instead of pure oxygen. The
use of lower purity
oxygen as the oxidizer may increase nitrogen oxides (NO,) in combustion gases,
but since all
combustion products are injected underground, there are no ill environmental
effects.

Figure 4 shows a conventional thermal oil process, with the water treatment
block and water
disposal and make-up streams highlighted. These water treatment process blocks
have been
required for all previous technologies because all previous thermal oil
processes use either
current industrial boilers, which have an upper limit to dissolved solids of
up to 5,000 ppm with
much lower thresholds for water hardness and silica, or have referenced
operating conditions for
direct fired boilers which require "dirty water" to still be below thrshholds
which require
softening. Those process blocks are all eliminated in the proposed embodiment.

CA 02751186 2011-08-31

14

In a typical thermal oil recovery process, the water treatment and handling
capital and operating
expenses can approach 50% of the total capital and operating costs. The
equipment required to
achieve the required water quality can constitute up to one-half of the
surface facility of a
thermal oil project. This invention thus has the result of drastically
lowering capital and
operating costs as well as a footprint of the facility.

A fourth embodiment of the invention, allows for the use of heavier fuels,
such as distillate or
heavy fuel oil, to create a larger fraction of carbon dioxide, as high as 35%.
In this embodiment,
the carbon dioxide mass fraction is tuned to the reservoir and oil parameters
to maximize
recovery.

A fifth embodiment of the invention allows for the addition of lighter
hydrocarbons or other
compounds to the steam carbon dioxide stream downstream of the steam
separator, to act as
additional solvents for use in hydrocarbon recovery.

A sixth embodiment of the invention allows for partial oxidation of the fuel
which, together with
pyrolysis and aquathermolysis, can produce a synthesis gas (consists of water,
hydrogen, carbon
dioxide, and carbon monoxide) which can be injected into the oil formation to
enable oil
recovery and partial upgrading if the injected gas is at sufficient
temperatures to enable in situ
gasification of the oil (typically above about 300 C).

Another benefit of injection of the water with trace amounts of oil and
impurities into the oxy-
fuel steam generator, is the use of those impurities as a fuel during the
burning process. In this
case, the impurities are incinerated and provide additional heat energy for
steam generation. Up
to 80% of the oil in the water may be consumed during this process.

The steam generated from the oxy-fuel steam generator can be used in various
thermal oil
recovery projects such as those illustrated in Figures 5, 6, 7 and 8. However,
this process can be
also used in other industries requiring the use of steam. Those industries may
include oil and gas
industries, chemical manufacturing industries, food industries, pharmaceutical
industries and
other. The process can be tailored to the requirement of the gas, allowed rate
of impurities in the
steam and the quality of the injected water.

CA 02751186 2011-08-31

15
While preferred embodiments of this invention have been shown and described,
modifications
thereof can be made by one skilled in the art without departing from the scope
or teaching of this
invention. The embodiments described herein arc exemplary only and are not
limiting. Many
variations and modifications of the system are possible and are within the
scope of the invention.
For further example, the relative dimensions of various parts, the materials
from which the
various parts are made an operating parameter can be varied, so long as the
system and methods
retain the advantages discussed herein. Accordingly, the scope of protection
is not limited to the
embodiments described herein, but is only limited by the claims that follow,
the scope of which
shall include all equivalents of the subject matter of the claims.

As many changes therefore may be made to the preferred embodiment of the
invention without
departing from the scope thereof. It is considered that all matter contained
herein be considered
illustrative of the invention and not in a limiting sense.

Representative Drawing
A single figure which represents the drawing illustrating the invention.
Administrative Status

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Administrative Status

Title Date
Forecasted Issue Date 2013-06-18
(22) Filed 2011-08-31
Examination Requested 2012-03-30
(41) Open to Public Inspection 2012-06-23
(45) Issued 2013-06-18

Abandonment History

There is no abandonment history.

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Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Registration of a document - section 124 $100.00 2011-08-31
Application Fee $400.00 2011-08-31
Request for Examination $800.00 2012-03-30
Final Fee $300.00 2013-04-11
Maintenance Fee - Application - New Act 2 2013-09-03 $100.00 2013-05-13
Registration of a document - section 124 $100.00 2013-07-17
Maintenance Fee - Patent - New Act 3 2014-09-02 $100.00 2014-06-09
Maintenance Fee - Patent - New Act 4 2015-08-31 $100.00 2015-08-20
Maintenance Fee - Patent - New Act 5 2016-08-31 $200.00 2016-08-23
Maintenance Fee - Patent - New Act 6 2017-08-31 $200.00 2017-06-30
Maintenance Fee - Patent - New Act 7 2018-08-31 $200.00 2018-08-01
Maintenance Fee - Patent - New Act 8 2019-09-03 $200.00 2019-08-06
Maintenance Fee - Patent - New Act 9 2020-08-31 $200.00 2020-08-10
Maintenance Fee - Patent - New Act 10 2021-08-31 $255.00 2021-08-03
Maintenance Fee - Patent - New Act 11 2022-08-31 $254.49 2022-07-28
Maintenance Fee - Patent - New Act 12 2023-08-31 $263.14 2023-07-24
Owners on Record

Note: Records showing the ownership history in alphabetical order.

Current Owners on Record
PAXTON CORPORATION
CLEAN ENERGY SYSTEMS, INC.
PARAMOUNT RESOURCES LTD.
Past Owners on Record
None
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.
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