Canadian Patents Database / 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
(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 (Country):
  • BUNIO, GARY L. (Canada)
  • GATES, IAN D. (Canada)
  • SUDLOW, PAUL (Canada)
  • ANDERSON, ROGER E. (United States of America)
  • PROPP, MURRAY E. (Canada)
(73) Owners (Country):
  • PAXTON CORPORATION (Canada)
  • CLEAN ENERGY SYSTEMS, INC. (United States of America)
  • PARAMOUNT RESOURCES LTD. (Canada)
(71) Applicants (Country):
  • 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.
(45) Issued: 2013-06-18
(22) Filed Date: 2011-08-31
(41) Open to Public Inspection: 2012-06-23
Examination requested: 2012-03-30
(30) Availability of licence: N/A
(30) Language of filing: English

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

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.


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.


A single figure which represents the drawing illustrating the invention.

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Admin Status

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

Maintenance Fee

Description Date Amount
Last Payment 2017-06-30 $200.00
Next Payment if small entity fee 2018-08-31 $100.00
Next Payment if standard fee 2018-08-31 $200.00

Note : If the full payment has not been received on or before the date indicated, a further fee may be required which may be one of the following

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Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Registration of Documents $100.00 2011-08-31
Filing $400.00 2011-08-31
Request for Examination $800.00 2012-03-30
Final $300.00 2013-04-11
Maintenance Fee - Application - New Act 2 2013-09-03 $100.00 2013-05-13
Registration of Documents $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

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Abstract 2011-08-31 1 14
Description 2011-08-31 15 686
Claims 2011-08-31 7 231
Drawings 2011-08-31 3 57
Cover Page 2012-06-19 1 32
Claims 2012-09-14 7 238
Drawings 2012-09-14 7 217
Description 2013-03-01 15 686
Claims 2013-03-01 7 250
Representative Drawing 2013-03-27 1 20
Cover Page 2013-05-29 1 51
Prosecution-Amendment 2011-10-31 3 109
Prosecution-Amendment 2011-11-09 1 32
Prosecution-Amendment 2012-03-30 4 123
Prosecution-Amendment 2012-08-02 2 64
Prosecution-Amendment 2012-07-04 1 20
Prosecution-Amendment 2012-09-14 18 554
Prosecution-Amendment 2012-12-04 3 98
Prosecution-Amendment 2013-03-01 35 1,323
Correspondence 2013-04-11 3 130
Fees 2013-05-13 1 163
Correspondence 2014-10-15 4 117
Correspondence 2014-10-21 1 24
Correspondence 2014-10-21 1 27
Fees 2016-08-23 1 33
Fees 2017-06-30 1 33