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
  • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid 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
  • E21B43/164—Injecting CO2 or carbonated water
• • 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

Definitions

• 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.
• production enhancement techniques req ⁇ ired including reservoir stimulation such as thermal or water/solvent flooding iii) Oil Sands and Bitumen
• GSG green house gases
• a further problem in the SAGD process is the upgrading required in the produced product to increase its value.
• 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 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.
• 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 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 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 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.
• Figure 1 is a schematic illustration of the generic methodology according to one embodiment
• 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 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
• Figure 9 is a schematic illustration of a cogeneration electric power generation operation.
• SAGD steam assisted gravity drainage
• SYNGAS refers to synthetic gas
• OTSG refers to once through steam generation
• GHG refers to green house gas
• BOPD barrels of oil per day
• COGEN refers to combined production of electric generation or compression service with heat recovery and steam generation
• HRSG refers to heat recovery steam generator
• "heavy oil” embraces heavy oil, extra heavy oil and bitumen as understood in the art.
• FIG. 10 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 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, 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.
• suitable hydrocarbon fuel non limiting examples -of which include natural gas, 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.
• This flue gas may contain numerous gaseous compounds including carbon dioxide, carbon monoxide, nitrogen, nitrogen oxides, hydrogen, sulfur dioxide, syngas inter alia.
• the treated injection gas 45 is injected into gas and heavy oil formation(s) generically denoted by numeral 18, shown in the example as a SAGD (steam assisted gravity drainage) formation.
• SAGD steam assisted gravity drainage
• 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 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 present invention.
• the techniques set forth herein can be applied not only to gas over bitumen formations, but also geographically proximate formations containing gas, bitumen or a combination thereof.
• laterally or vertically displaced formations can be exploited as well.
• Modified flue gas may be injected into 18' at 45'.
• the benefits of the instant technology also accrue for abandoned SAGD chambers or for 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 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, 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 represented by numeral 52 may be recirculated at 28, also to augment efficiency.
• an air separator unit 40 is provided for gaseous separation prior to injection of fuel and oxygen into the steam generation system 12.
• flue gas recirculation (FGR) circuit is provided for 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 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 herein after.
• 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, SO2 for commercial sales or H2 hydrogen supply for bitumen upgrading.
• bitumen leaving oil treatment 24 may be processed in a partial or full upgrader 56 with partially upgraded bitumen or synthetic crude being discharged 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 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.
• the flue gas 35 will contain less nitrogen for a fixed 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.
• Figure 3 represents the primary composition of the treated injection gas 45.
• graphically illustrated is the primary composition of the flue gas stream 35 prior to flue gas treatment in 14.
• Figure 5 is a schematic illustration of a natural gas steam production circuit.
• 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% 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.
• bitumen or heavy oil 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.
• processed bitumen exiting central treatment plant 62 at line 66 may be diverted in terms of a portion of the material 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.
• the suitable chemicals are added to the bitumen material (surfactants, etc.) in order to generate the alternate fuel.
• 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 its own.
• FIG 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.
• materials leaving central treatment plant 66 are upgraded in the upgrader 76 to formulate heavy residuum exiting at 80 which then can 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.
• one embodiment of the current invention is employed in combination with a conventional gas cogeneration (COGEN) plant 600 to enhance the overall thermal heavy oil recovery operation.
• COGEN gas cogeneration
• 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.
• HRSG COGEN heat recovery steam generator
• 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.

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• 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)
• Mechanical Engineering (AREA)
• General Chemical & Material Sciences (AREA)
• Thermal Sciences (AREA)
• Wood Science & Technology (AREA)
• General Engineering & Computer Science (AREA)
• Materials Engineering (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)

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• 2005
  • 2005-04-27 CA CA002505449A patent/CA2505449C/en not_active Expired - Fee Related
• 2006
  • 2006-02-02 NZ NZ545119A patent/NZ545119A/en not_active IP Right Cessation
  • 2006-02-03 AU AU2006200466A patent/AU2006200466B2/en not_active Ceased
  • 2006-02-06 MX MX2007013439A patent/MX2007013439A/es active IP Right Grant
  • 2006-02-06 NO NO20060582A patent/NO20060582L/no not_active Application Discontinuation
  • 2006-02-06 GB GB0602343A patent/GB2425550B/en not_active Expired - Fee Related
  • 2006-02-06 WO PCT/CA2006/000152 patent/WO2006113982A1/en active Application Filing
  • 2006-02-06 DE DE102006005277A patent/DE102006005277A1/de not_active Withdrawn
  • 2006-02-06 KR KR1020077024888A patent/KR101280016B1/ko not_active Expired - Fee Related
  • 2006-02-06 EA EA200602090A patent/EA013019B1/ru not_active IP Right Cessation
  • 2006-02-06 EP EP06705108.6A patent/EP1875039A4/en not_active Withdrawn
  • 2006-02-06 BR BRPI0607657-2A patent/BRPI0607657A2/pt not_active IP Right Cessation
  • 2006-02-07 FR FR0650429A patent/FR2885133B1/fr not_active Expired - Fee Related
  • 2006-02-07 JP JP2006030296A patent/JP2006307160A/ja active Pending
  • 2006-02-23 CN CN2006100081678A patent/CN1932237B/zh not_active Expired - Fee Related
• 2007
  • 2007-10-26 MA MA30327A patent/MA29441B1/fr unknown

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