NZ545119A - Flue gas injection for heavy oil recovery - Google Patents
Flue gas injection for heavy oil recoveryInfo
- Publication number
- NZ545119A NZ545119A NZ545119A NZ54511906A NZ545119A NZ 545119 A NZ545119 A NZ 545119A NZ 545119 A NZ545119 A NZ 545119A NZ 54511906 A NZ54511906 A NZ 54511906A NZ 545119 A NZ545119 A NZ 545119A
- Authority
- NZ
- New Zealand
- Prior art keywords
- flue gas
- formation
- gas
- set forth
- bitumen
- Prior art date
Links
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 title claims abstract description 77
- 239000003546 flue gas Substances 0.000 title claims abstract description 53
- 238000002347 injection Methods 0.000 title claims abstract description 36
- 239000007924 injection Substances 0.000 title claims abstract description 36
- 238000011084 recovery Methods 0.000 title claims abstract description 20
- 239000000295 fuel oil Substances 0.000 title claims description 34
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 58
- 239000010426 asphalt Substances 0.000 claims abstract description 55
- 238000000034 method Methods 0.000 claims abstract description 55
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 44
- 239000003345 natural gas Substances 0.000 claims abstract description 22
- 238000010796 Steam-assisted gravity drainage Methods 0.000 claims abstract description 20
- 239000000446 fuel Substances 0.000 claims description 47
- 239000007789 gas Substances 0.000 claims description 38
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims description 24
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 19
- 229910001868 water Inorganic materials 0.000 claims description 19
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 claims description 14
- 239000001301 oxygen Substances 0.000 claims description 14
- 229910052760 oxygen Inorganic materials 0.000 claims description 14
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 12
- 229910002092 carbon dioxide Inorganic materials 0.000 claims description 12
- 239000000203 mixture Substances 0.000 claims description 12
- 239000003921 oil Substances 0.000 claims description 12
- 239000001569 carbon dioxide Substances 0.000 claims description 11
- MWUXSHHQAYIFBG-UHFFFAOYSA-N nitrogen oxide Inorganic materials O=[N] MWUXSHHQAYIFBG-UHFFFAOYSA-N 0.000 claims description 9
- 239000005431 greenhouse gas Substances 0.000 claims description 7
- 239000006227 byproduct Substances 0.000 claims description 6
- 229930195733 hydrocarbon Natural products 0.000 claims description 6
- 150000002430 hydrocarbons Chemical class 0.000 claims description 6
- 229910052757 nitrogen Inorganic materials 0.000 claims description 6
- 238000010977 unit operation Methods 0.000 claims description 5
- 239000004215 Carbon black (E152) Substances 0.000 claims description 4
- 229910002091 carbon monoxide Inorganic materials 0.000 claims description 4
- 239000001257 hydrogen Substances 0.000 claims description 4
- 229910052739 hydrogen Inorganic materials 0.000 claims description 4
- 238000012545 processing Methods 0.000 claims description 4
- 239000003245 coal Substances 0.000 claims description 3
- 238000002485 combustion reaction Methods 0.000 claims description 3
- 238000007906 compression Methods 0.000 claims description 3
- 230000006835 compression Effects 0.000 claims description 3
- 239000007788 liquid Substances 0.000 claims description 3
- 239000002006 petroleum coke Substances 0.000 claims description 3
- 230000014759 maintenance of location Effects 0.000 claims description 2
- 125000004435 hydrogen atom Chemical class [H]* 0.000 claims 2
- XTQHKBHJIVJGKJ-UHFFFAOYSA-N sulfur monoxide Chemical class S=O XTQHKBHJIVJGKJ-UHFFFAOYSA-N 0.000 claims 2
- 229910052815 sulfur oxide Inorganic materials 0.000 claims 2
- 230000018044 dehydration Effects 0.000 claims 1
- 238000006297 dehydration reaction Methods 0.000 claims 1
- 239000002803 fossil fuel Substances 0.000 claims 1
- 238000010791 quenching Methods 0.000 claims 1
- 230000000171 quenching effect Effects 0.000 claims 1
- 230000008901 benefit Effects 0.000 abstract description 6
- 238000005516 engineering process Methods 0.000 abstract description 4
- 239000012530 fluid Substances 0.000 abstract description 3
- 230000007613 environmental effect Effects 0.000 abstract 1
- 238000005755 formation reaction Methods 0.000 description 34
- 238000004519 manufacturing process Methods 0.000 description 9
- 239000000839 emulsion Substances 0.000 description 7
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 5
- 150000001875 compounds Chemical class 0.000 description 4
- 239000000463 material Substances 0.000 description 4
- 239000008186 active pharmaceutical agent Substances 0.000 description 3
- 239000000047 product Substances 0.000 description 3
- 230000000638 stimulation Effects 0.000 description 3
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 2
- 239000003570 air Substances 0.000 description 2
- 238000013459 approach Methods 0.000 description 2
- 238000009472 formulation Methods 0.000 description 2
- 239000011159 matrix material Substances 0.000 description 2
- 239000002904 solvent Substances 0.000 description 2
- MGWGWNFMUOTEHG-UHFFFAOYSA-N 4-(3,5-dimethylphenyl)-1,3-thiazol-2-amine Chemical compound CC1=CC(C)=CC(C=2N=C(N)SC=2)=C1 MGWGWNFMUOTEHG-UHFFFAOYSA-N 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- MYMOFIZGZYHOMD-UHFFFAOYSA-N Dioxygen Chemical compound O=O MYMOFIZGZYHOMD-UHFFFAOYSA-N 0.000 description 1
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 1
- 238000010793 Steam injection (oil industry) Methods 0.000 description 1
- 230000003190 augmentative effect Effects 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 239000000571 coke Substances 0.000 description 1
- 238000009833 condensation Methods 0.000 description 1
- 230000005494 condensation Effects 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 125000004122 cyclic group Chemical group 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 229910003460 diamond Inorganic materials 0.000 description 1
- 239000010432 diamond Substances 0.000 description 1
- 238000005367 electrostatic precipitation Methods 0.000 description 1
- 230000002708 enhancing effect Effects 0.000 description 1
- 238000000605 extraction Methods 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 239000010763 heavy fuel oil Substances 0.000 description 1
- 150000002431 hydrogen Chemical class 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- JCXJVPUVTGWSNB-UHFFFAOYSA-N nitrogen dioxide Inorganic materials O=[N]=O JCXJVPUVTGWSNB-UHFFFAOYSA-N 0.000 description 1
- 238000010248 power generation Methods 0.000 description 1
- 238000000926 separation method Methods 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 238000004088 simulation Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
- C10G1/04—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by extraction
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
- E21B41/005—Waste disposal systems
- E21B41/0057—Disposal of a fluid by injection into a subterranean formation
- E21B41/0064—Carbon dioxide sequestration
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/18—Repressuring or vacuum methods
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2406—Steam assisted gravity drainage [SAGD]
- E21B43/2408—SAGD in combination with other methods
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F22—STEAM GENERATION
- F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
- F22B33/00—Steam-generation plants, e.g. comprising steam boilers of different types in mutual association
- F22B33/18—Combinations of steam boilers with other apparatus
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P30/00—Technologies relating to oil refining and petrochemical industry
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
- Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Organic Chemistry (AREA)
- Materials Engineering (AREA)
- Wood Science & Technology (AREA)
- General Chemical & Material Sciences (AREA)
- Thermal Sciences (AREA)
- Mechanical Engineering (AREA)
- General Engineering & Computer Science (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Treating Waste Gases (AREA)
- Working-Up Tar And Pitch (AREA)
- Solid Fuels And Fuel-Associated Substances (AREA)
Abstract
A variety of methods are disclosed for thermal recovery of natural gas and bitumen from a formation containing the latter. In general, the methods incorporate a series of existing, but previously un-combined technologies. A modified flue gas from the steam generators conventionally used in a SAGD recovery operation is injected into the formation to enhance recovery with the produced fluids, natural gas and bitumen being further processed. The injection of the flue gas conveniently is disposed of and further acts to re-pressurize the formation which otherwise becomes depressurized when depleted of natural gas. Accordingly, environmental and economic advantages are realized with the methodology.
Description
5A 5 1 1 9
*10050764538*
PATENTS FORM NO. 5
Fee No. 4: $250.00
PATENTS ACT 1953 COMPLETE SPECIFICATION
FLUE GAS INJECTION FOR HEAVY OIL RECOVERY
l/WE Diamond QC Technologies Inc., a Canadian company of Suite 1200, 202-6^ Avenue, S.W., Calgary, Alberta T2P 2R9, Canada hereby declare the invention, for which I/We pray that a patent may be granted to me/us, and the method by which it is to be performed to be particularly described in and by the following statement:
Intellectual Property Office? of N.Z.
1
P n r~n o-i» | To be followed by Page 1A
b L ! u j ! James & Wells Ref: 125814/0 RJ
RECEIVED :
FLUE GAS INJECTION FOR HEAVY OIL RECOVERY
The present invention relates to the thermal recovery of values from a subterranean formation by making use of a flue gas injection into the formation.
In the heavy oil industry, there are a broad range of classifications attributable to 5 the oil. The classes are essentially based on viscosity and density of the material and are generally broken down as follows:
i) Medium Heavy Oil 25°> °API > 18°
100 cPs >n> 10 cPs, mobile at reservoir conditions 10 ii) Extra Heavy Oil
°> °API > 12°
,000 cPs >y> 100 cPs, production enhancement techniques required including reservoir stimulation such as thermal or water/solvent flooding iii) Oil Sands and Bitumen 15 12°> °API > 6°, mined or thermal stimulation required
,000 cPs, production enhancement techniques required including reservoir stimulation such as thermal or thermal/solvent injection.
In view of the recognized value of vast reserves of heavy oil and bitumen potentially available in Canada, Central America, Russia, China and other locations of 2 0 the world, a varied panoply of extraction and handling techniques have come to light.
Currently, existing bitumen and extra heavy oil reservoirs are exploited using enhanced thermal recovery techniques resulting in efficiency of recovery in the range of between 20 and 25%. The most common thermal technique is steam injection where heat enthalpy from the steam is transferred to the oil by condensation. This, of course, 2 5 reduces the viscosity of the oil allowing gravity drainage and collection. Injection may be achieved by the well known cyclic steam simulation (CSS), Huff and Puff and Steam Assisted Gravity Drainage (SAGD).
Although SAGD is becoming widely employed, it is not without several detriments regarding efficiency. An area which presents significant costs is the fuel to 30 drive the steam generators to produce steam for injection. The most desirable fuel is
natural gas, but the expense greatly reduces the overall efficiency and this problem is compounded with the fact that green house gases (GHG) are liberated in varied amounts during operation of the steam generators using all types of hydrocarbon fuels. As an example, approximately 8,000 to 15,000 Tonnes daily of carbon dioxide is generated to 5 produce injection steam and produce 100,000 BOPD of bitumen.
A further problem in the SAGD process is the upgrading required in the produced product to increase its value.
As noted briefly above, another factor affecting SAGD is the limitation in recovery efficiency.
In an attempt to ameliorate some of the limitations noted, the use of alternate fuels other than natural gas has been proposed to at least reduce the ever increasingly impact of natural gas. An example of a suitable fuel for use in a SAGD operation is discussed in United States Patent No.6,530,965, issued to Warchol, March 11,2003. The document teaches the formation of predispersed residuum in an aqueous matrix 15 which is burnable as a alternate fuel.
Considering the problems with existing technologies, it remains desirable to have a method of enhancing efficiency in a SAGD operation, reducing the formation of excessive amounts of GHG and lowering costs by providing an alternate fuel with the thermal performance of natural gas.
2 0 The present invention collates all of the most desirable features and advantages noted with an energy efficient, high yield green environmentally friendly process.
One aspect of the present invention is to provide an improved thermal recovery process with enhanced efficiency.
A further aspect of one embodiment is to provide a method for recovering heavy 25 oil and bitumen from a subterranean formation containing heavy oil and bitumen, comprising: providing a fuel; burning the fuel in a flue gas recirculation circuit to produce an injection flue gas for injection into the formation; and injecting the injection flue gas into the formation to displace the heavy oil and bitumen.
InWe «,ai '•.,vtiy Oil!',fc' Qt ■*' /.
19 APR 2006 p r f" I \f r- r)
3
A still further aspect of one embodiment of the present invention is to provide a method for recovering heavy oil and bitumen from a subterranean formation containing heavy oil and bitumen, comprising: providing a fuel; burning the fuel in a flue gas recirculation circuit to produce a flue gas for injection into the formation; and injecting 5 the flue gas into the formation to displace the heavy oil and bitumen and natural gas.
Still another aspect of one embodiment of the present invention is to provide a method for recovering gas and bitumen from at least one of a steam assisted gravity drainage formation containing gas over bitumen within the volume of the formation and/or from a geographically proximate formation, comprising; providing a flue gas 10 recirculation circuit to produce modified flue gas; injecting the modified flue gas within the volume at a pressure sufficient to displace the gas over the bitumen and to displace the bitumen from within the formation; recovering displaced gas and bitumen; and maintaining the pressure or repressurizing the volume with the modified flue gas to a pressure substantially similar to a pressure prior to injection of the modified flue gas.
Yet another aspect of one embodiment of the present invention is to provide a method for recovering gas and bitumen from at least one of a steam assisted gravity drainage formation containing gas over bitumen within the volume of the formation and from a geographically proximate formation, comprising; a steam generation phase for generating steam for injection into the formation; a flue gas recirculation phase for 2 0 modifying flue gas for injection into the formation; an injection phase for injecting modified flue gas into the formation for displacing gas over the bitumen and maintaining the pressure or repressurizing the formation; and a processing phase for processing produced displaced gas and liquid liberated from the injection phase.
from the following detailed description, taken in combination with the appended
Having thus generally described the invention, reference will now be made to the accompanying drawings illustrating preferred embodiments and in which:
Figure 1 is a schematic illustration of the generic methodology according to one 3 0 embodiment;
Further features and advantages of the present invention will become apparent drawings.
Figure 2 is a more detailed schematic illustration of Figure 1;
Figure 3 is a graphical illustration of the oxygen requirement for flue gas carbon dioxide enrichment on a dry basis;
Figure 4 is a graphical illustration of the oxygen requirement for flue gas carbon 5 dioxide enrichment on a wet basis;
Figure 5 is a schematic illustration of natural gas steam production in a SAGD environment;
Figure 6 is a schematic illustration of bitumen or emulsion fuel steam production in a SAGD environment;
Figure 7 is a schematic illustration of residuum emulsion fuel steam production in a SAGD environment;
Figure 8 is a schematic illustration of a cogeneration flue gas compression operation; and
Figure 9 is a schematic illustration of a cogeneration electric power generation 15 operation.
Similar numerals employed in the description denote similar elements
It will be noted that throughout the appended drawings, like features are identified by like reference numerals.
2 0 PREFACE
Unless otherwise indicated, SAGD refers to steam assisted gravity drainage,
SYNGAS, refers to synthetic gas, OTSG refers to once through steam generation, GHG refers to green house gas, BOPD refers to barrels of oil per day, COGEN refers to combined production of electric generation or compression service with heat recovery 2 5 and steam generation, HRSG refers to heat recovery steam generator, and "heavy oil" embraces heavy oil, extra heavy oil and bitumen as understood in the art.
Intellectual pr,
Office of |\| ^
19 APR 2006
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r i w ^
* i
Referring now to Figure 1, shown is a schematic illustration of one embodiment of the present invention. Numeral 10 broadly denotes the overall process. An air, fuel and oxygen mixture combined with a Flue Gas Recirculation (FGR) stream is fed to a steam generation system 12 to generate steam 16 and flue gas 35. The air, fuel,oxygen 5 and FGR mixture is selected to create an enriched flue gas 35 to optimize recovery of gas and heavy oil from within a formation containing these. This will be discussed in greater detail herein after.
The fuel 20, contained in any of air or oxygen mixture, may be selected from any suitable hydrocarbon fuel, non limiting examples of which include natural gas, 10 bitumen, fuel oil, heavy oil, residuum, emulsified fuel, multiphase superfine atomized residue (MSAR, a trademark of Quadrise Canada Fuel Systems), asphaltenes, petcoke, coal, and combinations thereof.
Flue gas 35 from the system 12 is treated or modified in a treatment operation 14 prior to injection within a formation. By products generated from treatment unit 14 may 15 optionally be recovered. This flue gas may contain numerous gaseous compounds including carbon dioxide, carbon monoxide, nitrogen, nitrogen oxides, hydrogen, sulfur dioxide, syngas inter alia. At excess oxygen burning conditions, where oxygen levels are present in the flue gas 35, the flue gas 35 will primarily contain carbon dioxide, nitrogen and water vapour. The treated injection gas 45 is injected into gas and heavy 20 oil formation(s) generically denoted by numeral 18, shown in the example as a SAGD (steam assisted gravity drainage) formation. As is well known, this technique involves the use of steam to assist in reducing the viscosity of viscous hydrocarbons to facilitate mobility. These formations also contain natural gas, bitumen and a variety of other hydrocarbons which have value, but which were previously marginally economic or 25 fiscally unfeasible to recover. Steam 16 from system 12 is introduced into the formation 18 as illustrated.
The gas in the formation 18 is now made recoverable in an efficient manner in view of the flue gas circuit in combination with injection of the modified flue gas 45. The union of these operations has resulted in the success of the methodology of the 30 present invention. Advantageously, the techniques set forth herein can be applied not only to gas over bitumen formations, but also geographically proximate formations
6
containing gas, bitumen or a combination thereof. As a non limiting example, laterally or vertically displaced formations can be exploited as well. This is generally shown in Figure 1 and denoted by numeral 18'. Modified flue gas may be injected into 18' at 45'. The benefits of the instant technology also accrue for abandoned SAGD chambers or for 5 blowdown where flue gas can be injected to not only maintain heavy oil recovery, but also to displace the heavy oil.
Natural gas 25 displaced from formation 18 is collected and may be subjected to additional unit operations or a portion may be recirculated into the system as fuel for steam generation. This latter step is not shown in Figure 1, but is well within the 10 purview of one skilled.
Mobilized production fluids, containing bitumen denoted by numeral 22 are then subjected to an oil treatment operation 24 where the bitumen 26 is processed for the removal of entrained water to produce a saleable product. Produced water 26 is further treated in a suitable water treatment unit 28 to remove bitumen, hardness compounds, 15 silica and any other undesirable compounds making the water suitable of boiler feed water 30. Any suitable water treatment operations may be employed to achieve the desired result. Boiler feed water 30 may then be recirculated into system 12 for steam 16 production, thus reducing water demands in the process to augment efficiency. Further to this, water evolved from the flue gas treatment operation, the water being 2 0 represented by numeral 52 may be recirculated at 28, also to augment efficiency.
Having broadly discussed the overall process, numerous advantages attributable to the process are evinced. These include:
i) an efficient and environmentally safe disposal of harmful flue gas;
ii) improved gas recovery from the formation;
2 5 iii) enhanced thermal recovery operation to produce more bitumen per unit steam;
iv) carbon dioxide sequestering to reduce GHG emissions;
v) volumetric replacement within the formation; and vi) any combination of these features.
Referring now to Figure 2, shown is a more detailed schematic of the process according to one embodiment. In the embodiment shown, an air separator unit 40 is provided for gaseous separation prior to injection of fuel and oxygen into the steam generation system 12. Optionally, flue gas recirculation (FGR) circuit is provided for 5 the system 12. The flue gas recirculation is useful to reduce the temperature of the combustion zone in the system 12 in order to maintain compatible steam generator performance for the full range of oxygen input versus combustionair used in steam generation process. Without the flue gas recirculation (FGR) for higher levels of oxygen, the heat generator temperature would exceed the design limitations of the steam 10 generators. The flue gas exiting the circuit is processed in treatment unit 14, where it is subjected to particulate removal, such as electrostatic precipitation or baghouse 44, with the ash discharged at 46. The so treated gas is further quenched prior to being compressed at 48 and further dehydrated at 50. Water 52 from the operation can be circulated to the water treatment unit 28 or a MSAR formulation phase 70 discussed 15 herein after. By product gas from 14, if produced, can be separated and recovered from the flue gas and used for further operations such as CO fuel for process furnaces or boilers, S02 for commercial sales or H2 hydrogen supply for bitumen upgrading.
In this example, bitumen leaving oil treatment 24 may be processed in a partial or full upgrader 56 with partially upgraded bitumen or synthetic crude being discharged 20 at 58 and a hydrocarbon mixture consisting of bitumen, residuum, asphaltenes, or coke etc. may be further processed into MSAR, an efficient fuel discussed in detail in United States Patent No. 6,530,965, comprising essentially a predispersed residuum in an aqueous matrix which greatly reduces the fuel cost to operate the steam generation system. Traditionally, the latter was done with natural gas, the cost for which greatly
2 5 exceeded the cost involved with the use of MSAR. As an option, the fuel may be supplanted or augmented by those fuels previously taught.
Figures 3 and 4 graphically depict the oxygen requirement for flue gas carbon dioxide enrichment on a dry and wet basis, respectively. As pure oxygen is introduced to the steam generator operation, the flue gas 35 will contain less nitrogen for a fixed
3 0 quantity of carbon dioxide. Therefore both the volume of flue gas is reduced and the concentration of carbon dioxide in the injection treated gas 45 is increasing. For example, on a dry basis with reference to Figure 3, as the oxygen level used approaches
Intel!:
8 Gt U B, 1 Pro p 0 rty
Office of N.Z.
100% (0% combustion air), then the composition of the treated flue gas approaches near 100% CO2, including minor compounds of carbon monoxide, sulfur dioxide, nitrogen dioxide, etc. Figure 3 represents the primary composition of the treated injection gas 45. Referring to Figure 4, graphically illustrated is the primary composition of the flue 5 gas stream 35 prior to flue gas treatment in 14.
Figure 5 is a schematic illustration of a natural gas steam production circuit. In the example, at least a portion of the displaced natural gas 20 may be recirculated as a fuel to drive the steam generation system 12. This is denoted by numeral 60. The enriched injection flue gas, which may be customized to contain between 30% and 50% 10 nitrogen and between 70% and 50% carbon dioxide, is injected to displace the produced fluids, bitumen, natural gas, water etc processed for upgrading at 62. The choice of operations conducted at 62 will depend upon the desired products.
Recovered water 52 from the flue gas treatment unit 14 may be recirculated to
62.
Referring to Figure 6, shown is a further variation on the process where the steam generation is achieved by making use of a liquid alternate fuel, shown in the example is a bitumen or heavy oil fuel, or alternatively, the bitumen or heavy oil is transformed into an emulsion fuel. In this arrangement, processed bitumen exiting central treatment plant 62 at line 66 may be diverted in terms of a portion of the material 2 0 only at line 68 directly as heavy fuel oil or alternatively, directed into an emulsion unit for generating an alternate fuel. The emulsion unit stage being indicated by numeral 70. An additional amount of water recovered and circulated at 52 may be diverted and introduced into the unit 70 via line 72. In the emulsion fuel unit, the suitable chemicals are added to the bitumen material (surfactants, etc.) in order to generate the alternate 25 fuel. At this point, once formulated, the alternate fuel exiting the unit at 74 may be introduced as a fuel to drive the steam generation system 12. The natural gas feed from the displaced gas in the formulation 18 used as fuel ceases and the process does not deplete any further volume of the natural gas. In this manner, once the emulsion unit is operational and stabilized, the process simply relies on alternate fuel that it generates on 30 its own.
9
Referring to Figure 7, shown is a further variation in the arrangement shown in Figure 6 where a bitumen upgrader 76 is shown added to the unit operation of the central treatment plant. In this manner, materials leaving central treatment plant 66 are upgraded in the upgrader 76 to formulate heavy residuum exiting at 80 which then can 5 be formulated into an emulsified alternate fuel and introduced into steam system 12 as noted with respect to Figure 6. Subsequent benefit can be realized in the upgrading of the bitumen quality to deasphalted oil or synthetic crude oil.
Referring to Figure 8, whereby one embodiment of the current invention is employed in combination with a conventional gas cogeneration (COGEN) plant 600 to 10 enhance the overall thermal heavy oil recovery operation. Uniquely, when the current embodiment is combined, the steam generators 12 as described previously can be suitably fitted with COGEN heat recovery steam generator (HRSG) to produce the required total injection steam and provide the required power to drive the treated injection flue gas compressors.
Figure 9 further illustrates a further embodiment whereby the steam generators
12 are combined with a COGEN plant 600 to generate electric power. The electric power generated could be used to drive the treated flue gas compressors and power the full facility 10 to make it self sufficient in energy.
Although embodiments of the invention have been described above, it is limited 2 0 thereto and it will be apparent to those skilled in the art that numerous modifications form part of the present invention insofar as they do not depart from the spirit, nature and scope of the claimed and described invention.
1 * APR 2006
R B A M
f r- r>, I - 10 -
Claims (25)
1. A method for recovering heavy oil and bitumen from a subterranean formation containing heavy oil and bitumen, comprising: providing a fuel; burning said fuel in a flue gas recirculation circuit to produce a flue gas for injection into said formation; injecting said flue gas into said formation to displace said heavy oil and bitumen; and repressurizing said formation with said flue gas to a pressure substantially similar to a pressure prior to injection of said flue gas.
2. The method as set forth in claim 1, wherein said fuel is a fossil fuel.
3. The method as set forth in claim 2, wherein said fuel is selected from the group consisting of natural gas, fuel oil, heavy oil, bitumen, residuum, emulsified fuel, multiphase superfine atomized residue, asphaltenes, petcoke, coal and combinations thereof.
4. The method as set forth in claims 1 through 3, wherein said fuel is combusted in a steam generator with oxygen and air.
5. The method as set forth in claims 1 through 4, further including the step of modifying said flue gas prior to injection into said formation.
6. The method as set forth in claim 5, including removing byproduct gas generated during said step of modifying.
7. The method as set forth in claim 6, wherein said byproduct gas includes at least one of hydrogen, carbon monoxide, nitrogen, nitrogen oxides, sulfur oxides, and carbon dioxide. iirteitectual Property , Office of N.Z. \ ] - 8 AUG 2007 - 11 -
8. The method as set forth in any one of claims 5 through 7, including removing particulate ash.
9. The method as set forth in any one of claims 5 through 8, wherein said step of modifying said flue gas comprises unit operations including departiculation, quenching, compression and dehydration.
10. The method as set forth in any one of claims 5 through 9, wherein modified flue gas is injected into said formation for repressurizing said formation and releasing natural gas within said formation.
11. The method as set forth in claim 10, wherein heavy oil is displaced from said formation during repressurization.
12. The method as set forth in claim 11, further including the step of modifying said displaced heavy oil with upgrading unit operations.
13. The method as set forth in claim 12, wherein said upgrading unit operations including water removal from oil displaced from said formation.
14. The method as set forth in claim 13, wherein at least a portion of removed water is recirculated into said steam generator.
15. The method as set forth in any one of claims 12 through 14, wherein at least a portion of the residuum from the upgraded heavy oil is converted to a multiphase superfine atomized residue for use as a combustion fuel.
16. A method for recovering gas and bitumen from at least one of a steam assisted gravity drainage formation containing gas over bitumen within the volume of said formation and from a geographically proximate formation, comprising; /' providing a flue gas recirculation circuit to produce modified flue gas; I In ti- <!,; . I bf:-~3 of KZ I IS APR 2336 - 12 - injecting said modified flue gas within said volume at a pressure sufficient to displace said gas over said bitumen and to displace said bitumen from within said formation; recovering displaced gas and bitumen; and repressurizing or maintaining the pressure of said volume with said modified flue gas to a pressure substantially similar to a pressure prior to injection of said modified flue gas.
17. The method as set forth in claim 16, wherein said displaced gas comprises natural gas not in direct geological contact with the bitumen.
18. The method as set forth in claim 16 or 17, further including the step of forming a composition of said modified flue gas for maximizing the volume of displaced gas.
19. The method as set forth in any one of claims 16 through 18, wherein subsequent to displaced gas recovery, modified flue gas injection is continued to a pressure substantially similar to original geological pressures for further sequestering of green house gases GHG.
20. The method as set forth in claim 18 or 19, wherein said step of forming a composition of said modified flue gas includes maintaining an oxygen concentration in said modified flue gas selected from the group consisting of excess, stoichiometric and sub stoichiometric.
21. The method as set forth in any one of claims 18 through 20, wherein said composition of said modified flue gas comprises between 0 % and 79% by volume nitrogen.
22. The method as set forth in any one of claims 16 through 21, further including the step of generating by product gas from said modified flue gas. iru i I irty OlliUfc O! 13 APR 2006 fTJ T" -» -r q ,, pjf i - 13 -
23. The method as set forth in claim 22, wherein said byproduct gas at least includes one of hydrogen, carbon monoxide, nitrogen oxides, sulfur oxides, and carbon dioxide.
24. The method as set forth in any one of claims 16 through 23, wherein said flue gas recirculation circuit is fueled with a hydrocarbon fuel selected from the group consisting of natural gas, fuel oil, heavy oil, bitumen, residuum, vacuum residuum, emulsified fuel, multiphase superfine atomized residue,asphaltenes, petcoke, coal and combinations thereof.
25. A method for recovering gas and bitumen from at least one of a steam assisted gravity drainage formation containing gas over bitumen within the volume of said formation and from a geographically proximate formation, comprising; a steam generation phase for generating steam for injection into said formation; a flue gas recirculation phase for modifying flue gas for injection into said formation; an injection phase for injecting modified flue gas into said formation for displacing gas over said bitumen and maintaining the pressure of or repressurizing said formation; and a processing phase for processing produced displaced gas and liquid liberated from said injection phase. ronarty Inic 'i ,, p Oi.it-- of JV,2. t y APR 2006 "> f*. (fo- s .
Applications Claiming Priority (1)
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CA002505449A CA2505449C (en) | 2005-04-27 | 2005-04-27 | Flue gas injection for heavy oil recovery |
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JP (1) | JP2006307160A (en) |
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2006
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- 2006-02-06 WO PCT/CA2006/000152 patent/WO2006113982A1/en active Application Filing
- 2006-02-06 DE DE102006005277A patent/DE102006005277A1/en not_active Withdrawn
- 2006-02-06 EA EA200602090A patent/EA013019B1/en not_active IP Right Cessation
- 2006-02-06 BR BRPI0607657-2A patent/BRPI0607657A2/en not_active IP Right Cessation
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BRPI0607657A2 (en) | 2009-09-22 |
MA29441B1 (en) | 2008-05-02 |
CA2505449A1 (en) | 2006-02-07 |
MX2007013439A (en) | 2008-01-14 |
CN1932237A (en) | 2007-03-21 |
KR101280016B1 (en) | 2013-07-01 |
GB2425550B (en) | 2010-06-02 |
GB0602343D0 (en) | 2006-03-15 |
JP2006307160A (en) | 2006-11-09 |
KR20080028354A (en) | 2008-03-31 |
NO20060582L (en) | 2006-10-30 |
EA200602090A1 (en) | 2008-06-30 |
AU2006200466B2 (en) | 2010-02-18 |
WO2006113982A1 (en) | 2006-11-02 |
GB2425550A (en) | 2006-11-01 |
FR2885133B1 (en) | 2010-12-31 |
EA013019B1 (en) | 2010-02-26 |
CA2505449C (en) | 2007-03-13 |
DE102006005277A1 (en) | 2006-11-09 |
FR2885133A1 (en) | 2006-11-03 |
EP1875039A4 (en) | 2013-06-19 |
AU2006200466A1 (en) | 2006-11-16 |
EP1875039A1 (en) | 2008-01-09 |
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