CA2947365A1 - Method of and apparatus for asphaltene combustion at the sagd central processing facility - Google Patents
Method of and apparatus for asphaltene combustion at the sagd central processing facility Download PDFInfo
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- CA2947365A1 CA2947365A1 CA2947365A CA2947365A CA2947365A1 CA 2947365 A1 CA2947365 A1 CA 2947365A1 CA 2947365 A CA2947365 A CA 2947365A CA 2947365 A CA2947365 A CA 2947365A CA 2947365 A1 CA2947365 A1 CA 2947365A1
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- flue gas
- steam
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- asphaltenes
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
- F23L7/00—Supplying non-combustible liquids or gases, other than air, to the fire, e.g. oxygen, steam
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN A CARRIER GAS OR AIR
- F23C3/00—Combustion apparatus characterised by the shape of the combustion chamber
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN A CARRIER GAS OR AIR
- F23C9/00—Combustion apparatus characterised by arrangements for returning combustion products or flue gases to the combustion chamber
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN A CARRIER GAS OR AIR
- F23C99/00—Subject-matter not provided for in other groups of this subclass
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
- F23L7/00—Supplying non-combustible liquids or gases, other than air, to the fire, e.g. oxygen, steam
- F23L7/007—Supplying oxygen or oxygen-enriched air
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23C—METHODS OR APPARATUS FOR COMBUSTION USING FLUID FUEL OR SOLID FUEL SUSPENDED IN A CARRIER GAS OR AIR
- F23C2900/00—Special features of, or arrangements for combustion apparatus using fluid fuels or solid fuels suspended in air; Combustion processes therefor
- F23C2900/09001—Cooling flue gas before returning them to flame or combustion chamber
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
- F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
- F23L2900/07001—Injecting synthetic air, i.e. a combustion supporting mixture made of pure oxygen and an inert gas, e.g. nitrogen or recycled fumes
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F23—COMBUSTION APPARATUS; COMBUSTION PROCESSES
- F23L—SUPPLYING AIR OR NON-COMBUSTIBLE LIQUIDS OR GASES TO COMBUSTION APPARATUS IN GENERAL ; VALVES OR DAMPERS SPECIALLY ADAPTED FOR CONTROLLING AIR SUPPLY OR DRAUGHT IN COMBUSTION APPARATUS; INDUCING DRAUGHT IN COMBUSTION APPARATUS; TOPS FOR CHIMNEYS OR VENTILATING SHAFTS; TERMINALS FOR FLUES
- F23L2900/00—Special arrangements for supplying or treating air or oxidant for combustion; Injecting inert gas, water or steam into the combustion chamber
- F23L2900/07002—Injecting inert gas, other than steam or evaporated water, into the combustion chambers
-
- 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
- Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
- Y02E20/00—Combustion technologies with mitigation potential
- Y02E20/32—Direct CO2 mitigation
-
- 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
- Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
- Y02E20/00—Combustion technologies with mitigation potential
- Y02E20/34—Indirect CO2mitigation, i.e. by acting on non CO2directly related matters of the process, e.g. pre-heating or heat recovery
Abstract
Hot, liquid asphaltenes from the BEST ®1 Asphaltene Removal Process, or any of the solvent deasphalting processes can be pumped to a sufficient pressure, to be burned, and for the flue gas to go through heat exchangers, to produce steam, and still be at high enough pressure to be mixed with HP Steam and sent to the injection well of a SAGD Facility. Liquid oxygen can also be pumped to the same pressure. Therefore, it is logical for the combustion to be carried out at that pressure so that the CO2 and H2O products from the combustion can be sent to the injection well without the need for recompression. Byproducts of the combustion, SO2 and NO2, will also be mixed with HP Steam and sent to the injection well of the SAGD Facility. In order to cut down on the amount of CO2 that is being emitted in the production of bitumen or extraheavy oil in a SAGD Facility, it has been identified that the least valuable liquid in bitumen is the asphaltene fraction. Therefore, a new process has been invented to burn the asphaltenes at the SAGD Central Processing Facility and at a high enough pressure to send the flue gas into the injection well.
Description
Description TECHNICAL FIELD
This invention relates to recovering a pumpable crude oil from a reservoir of extraheavy oil or bitumen by the steam-assisted gravity drainage (SAGD) process, and more particularly to an asphaltene removal process to remove an asphaltene fraction from the bitumen or extraheavy oil to produce a deasphalted bitumen or deasphalted extraheavy oil that requires significantly less diluent to get into the pipeline, combusting the hot liquid asphaltenes at a significant pressure to supply the heat for generation of the injection steam and then be mixed with the injection steam. The purpose for mixing the flue gas with the injection steam is that about 37.7% of the flue gas is steam suitable for injection, about 59.6% is carbon dioxide (CO2), about 2.1 vol% is sulfur dioxide (SO2), and about 0.7% nitrogen dioxide (NO2). CO2 is normally co-injected with steam at the end of the well life to maximize recovery from the well. Recently, one of the producers started a field test of co-injecting CO2 with steam during the production life of a SAGD
well. This should allow an increased production rate at the same steam to oil ratio, or the same production at a lower steam to oil ratio, because some of the CO2 will dissolve in the bitumen or the extraheavy oil reducing its viscosity so that it will flow at a lower temperature. SO2 and NO2 may or may not have the same effect as the CO2, but since all three of these compounds are gases at the reservoir conditions if the pressure is less than 7,377 kPa, they will stay in the reservoir as a gas cap above the bitumen. Any of these compounds that come out of the reservoir, dissolved in the bitumen or extraheavy oil, can be recovered, recompressed, and sent back down the injection well until there is no more recoverable oil in the reservoir. By doing this the total CO2, S02, and NO2 released to the atmosphere for the entire production is negligible. Since the asphaltenes have about 15% more heat content than is required for a 3:1 steam to oil ratio, it is highly likely that co-injecting the flue gas into the reservoir will result in clean electiricity production.
BACKGROUND OF THE INVENTION
Extraheavy crude oil reservoirs contain crude petroleum having a viscosity of more than 1,000 cP but less than 10,000 cP at reservoir conditions. Bitumen is crude petroleum, with an API Gravity of 6 to 12 API and immobile at reservoir conditions (greater than 10,000 cP viscosity at 8-12 C). Bitumen is recovered by one of two possible techniques. For Bitumen near the surface, surface mining techniques are applicable.
Most of the Bitumen is too deep for surface mining techniques. Therefore the Steam Assisted Gravity Drainage (SAGD) process was developed. In order to heat the reservoir and the bitumen up to a temperature, where the bitumen viscosity is low enough to pump, a large amount of heat is needed. Up until now, the primary fuel being burned to provide the heat was natural gas burned using air as the oxygen source. This Page 4 of 10 releases a large amount of CO2 into the atmosphere. In order for bitumen to be a viable source of transportation fuel, in the future, the amount of CO2 being released in its production needs to be curtailed.
As can be seen in Fig. 1, natural gas releases the least amount of CO2 per unit of heat generated (about 46% lower) for fuels readily available in Alberta.
Unfortunately, natural gas is normally burned using air; therefore, the flue gas would have to be cooled and compressed to a high enough pressure to get into the injection well.
Solid fuels such as wood, petroleum coke, and coal are difficult to get up to the pressure needed to have the flue gas generate steam and then go directly into the injection well without recompression. These solid fuels are quite easily transported. Since the SAGD
producer already has a significant quantity of asphaltenes in the produced bitumen, all which is required to do is remove the asphaltenes from the produced bitumen or extraheavy oil, burn them and inject the flue gas into the reservoir.
Canadian patent application number 2,932,517, with a title of "Method of and Apparatus for Upgrading Diluted Bitumen at the SAGD Central Processing Facility"
discloses processes for diluent removal and asphaltene removal from the bitumen at the SAGD
Facility.
When the asphaltenes are fed to a gasifier, they are burned with oxygen to produce primarily carbon monoxide (45.6% CO) and hydrogen (43.3% H2) with about 8-10%
carbon dioxide (CO2) and small amounts of H20, CH4, Ar, N2, and H2S, and potentially some COS. The partial combustion develops some heat that can be used to generate steam to inject into the reservoir. As can be seen in Fig. 2, immediately after the steam generation and the Boiler feed water preheat, the flue gas is quenched with liquid water, condensing any steam that was a product of the partial combustion, and could have been injected to produce more bitumen. After the flue gas is quenched with the steam condensed, the raw syngas is sent to gas treatment, and presumably after that further combustion of CO to CO2. So for gasification the flue gas also needs to be compressed to a high enough pressure to get into the injection well.
The asphaltenes from a typical asphaltene from bitumen has an atomic ratio of hydrogen to carbon of 1.27, therefore, the ratio of steam (H20) to CO2 in the flue gas is 0.633. In other words, the products of the combustion are 59.6% CO2, 37.7%
H20,
This invention relates to recovering a pumpable crude oil from a reservoir of extraheavy oil or bitumen by the steam-assisted gravity drainage (SAGD) process, and more particularly to an asphaltene removal process to remove an asphaltene fraction from the bitumen or extraheavy oil to produce a deasphalted bitumen or deasphalted extraheavy oil that requires significantly less diluent to get into the pipeline, combusting the hot liquid asphaltenes at a significant pressure to supply the heat for generation of the injection steam and then be mixed with the injection steam. The purpose for mixing the flue gas with the injection steam is that about 37.7% of the flue gas is steam suitable for injection, about 59.6% is carbon dioxide (CO2), about 2.1 vol% is sulfur dioxide (SO2), and about 0.7% nitrogen dioxide (NO2). CO2 is normally co-injected with steam at the end of the well life to maximize recovery from the well. Recently, one of the producers started a field test of co-injecting CO2 with steam during the production life of a SAGD
well. This should allow an increased production rate at the same steam to oil ratio, or the same production at a lower steam to oil ratio, because some of the CO2 will dissolve in the bitumen or the extraheavy oil reducing its viscosity so that it will flow at a lower temperature. SO2 and NO2 may or may not have the same effect as the CO2, but since all three of these compounds are gases at the reservoir conditions if the pressure is less than 7,377 kPa, they will stay in the reservoir as a gas cap above the bitumen. Any of these compounds that come out of the reservoir, dissolved in the bitumen or extraheavy oil, can be recovered, recompressed, and sent back down the injection well until there is no more recoverable oil in the reservoir. By doing this the total CO2, S02, and NO2 released to the atmosphere for the entire production is negligible. Since the asphaltenes have about 15% more heat content than is required for a 3:1 steam to oil ratio, it is highly likely that co-injecting the flue gas into the reservoir will result in clean electiricity production.
BACKGROUND OF THE INVENTION
Extraheavy crude oil reservoirs contain crude petroleum having a viscosity of more than 1,000 cP but less than 10,000 cP at reservoir conditions. Bitumen is crude petroleum, with an API Gravity of 6 to 12 API and immobile at reservoir conditions (greater than 10,000 cP viscosity at 8-12 C). Bitumen is recovered by one of two possible techniques. For Bitumen near the surface, surface mining techniques are applicable.
Most of the Bitumen is too deep for surface mining techniques. Therefore the Steam Assisted Gravity Drainage (SAGD) process was developed. In order to heat the reservoir and the bitumen up to a temperature, where the bitumen viscosity is low enough to pump, a large amount of heat is needed. Up until now, the primary fuel being burned to provide the heat was natural gas burned using air as the oxygen source. This Page 4 of 10 releases a large amount of CO2 into the atmosphere. In order for bitumen to be a viable source of transportation fuel, in the future, the amount of CO2 being released in its production needs to be curtailed.
As can be seen in Fig. 1, natural gas releases the least amount of CO2 per unit of heat generated (about 46% lower) for fuels readily available in Alberta.
Unfortunately, natural gas is normally burned using air; therefore, the flue gas would have to be cooled and compressed to a high enough pressure to get into the injection well.
Solid fuels such as wood, petroleum coke, and coal are difficult to get up to the pressure needed to have the flue gas generate steam and then go directly into the injection well without recompression. These solid fuels are quite easily transported. Since the SAGD
producer already has a significant quantity of asphaltenes in the produced bitumen, all which is required to do is remove the asphaltenes from the produced bitumen or extraheavy oil, burn them and inject the flue gas into the reservoir.
Canadian patent application number 2,932,517, with a title of "Method of and Apparatus for Upgrading Diluted Bitumen at the SAGD Central Processing Facility"
discloses processes for diluent removal and asphaltene removal from the bitumen at the SAGD
Facility.
When the asphaltenes are fed to a gasifier, they are burned with oxygen to produce primarily carbon monoxide (45.6% CO) and hydrogen (43.3% H2) with about 8-10%
carbon dioxide (CO2) and small amounts of H20, CH4, Ar, N2, and H2S, and potentially some COS. The partial combustion develops some heat that can be used to generate steam to inject into the reservoir. As can be seen in Fig. 2, immediately after the steam generation and the Boiler feed water preheat, the flue gas is quenched with liquid water, condensing any steam that was a product of the partial combustion, and could have been injected to produce more bitumen. After the flue gas is quenched with the steam condensed, the raw syngas is sent to gas treatment, and presumably after that further combustion of CO to CO2. So for gasification the flue gas also needs to be compressed to a high enough pressure to get into the injection well.
The asphaltenes from a typical asphaltene from bitumen has an atomic ratio of hydrogen to carbon of 1.27, therefore, the ratio of steam (H20) to CO2 in the flue gas is 0.633. In other words, the products of the combustion are 59.6% CO2, 37.7%
H20,
2.1% SO2, 0.7% NO2, and 2-4% 02. Asphaltene gasification throws away 37.7%
steam to remove 2.8% SO2 and NO2.
Page 5 of 10 BRIEF DESCRIPTION OF THE INVENTION
In accordance with present invention, at an existing Steam Assisted Gravity Drainage (SAGD) Facility, asphaltenes in their hot, liquid form are pumped to an asphaltene combustor shown in Fig. 3 that is very similar to the gasification reactor in a gasification unit. Steam is used to help distribute the asphaltenes into the combustion zone. Liquid oxygen is also pumped to the asphaltene combustor in order to minimize the amount of NO2 that is sequestered in the top of the reservoir. The flue gas from the asphaltene combustor is cooled in the Flue Gas Effluent Cooler very similar to the syngas effluent cooler in a gasification unit. The Flue Gas Effluent Cooler transfers heat from the flue gas to boiler feed water in order to produce steam at the pressure required for the injection well. Due to approach temperatures, the flue gas will still be at a higher temperature than the high pressure steam. Therefore, the flue gas exiting the Flue Gas Effluent Cooler is further cooled by exchanging heat with the boiler feed water that is being sent to the Flue Gas Effluent Cooler, after an amine has been added in order to prevent acidic corrosion in the heat exchange with the boiler feed water or in the lines to the reservoir.
By combusting the asphaltenes in this manner, the water that is a byproduct of the full combustion, is already mixed with the CO2, SO2, and NO2 that are also byproducts of the full combustion. Then the flue gas mixture is mixed with the steam that is going to the SAGD Injection wells.
Page 6 of 10 BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a graph showing the amount of CO2 produced for fuel sources available in Alberta. In addition it shows the CO2 released to the atmosphere when the BEST
Asphaltene Combustion Process is used to burn the asphaltenes;
FIG. 2 is a Typical Shell Residue Gasification Process Scheme showing that the Syngas is quenched to below the boiling point of water and the final combustion step is at a significantly lower pressure than the gasification reactor, so a compressor would be required to get the flue gas back up to the reservoir pressure;
FIG. 3 is a block diagram of the embodiment of the present invention for burning the asphaltenes to produce steam and ensuring that that the flue gas, including the steam byproduct of the combustion is at a sufficient pressure to mix with the steam going to the injection wells.
DETAILED DESCRIPTION
Referring now to FIG. 3, reference numeral 11 designates a typical asphaltene stream produced by a solvent deasphalting unit or an asphaltene removal unit, such as the BEST 1 Asphaltene Removal Unit, specifically designed for use at a Steam Assisted Gravity Drainage (SAGD) facility. Reference numeral 12 is steam that is used to help atomize the asphaltenes for combustion. Reference numeral 13 is liquid oxygen supplied by others that is preheated in reference numeral 14, the oxygen preheater.
Reference numeral 15, the preheated oxygen, is injected into reference numeral 16, the Asphaltene Combustor. Excess oxygen in the range from 1-4% of the amount needed for burning the asphaltenes to complete combustion, is used to ensure that there is complete combustion. Reference numeral 17, the flue gas, primarily CO2 and H20 that flows from reference numeral 16, the Asphaltene Combustor, to reference numeral 21, the Flue Gas Effluent Cooler. Reference numeral 18, pressurized boiler feed water is preheated in reference number 19, the Boiler Feed Water Preheater, by exchanging heat with reference numeral 27, the flue gas outlet from reference numeral 21.
Reference numeral 28, an amine stream, is added to reference numeral 27 before entering reference numeral 19 in order to prevent acidic attack resulting in corrosion in reference numeral 19 and all lines containing flue gas downstream of reference numeral 19. Reference numeral 29 is temperature controlled so that the temperature of reference numeral 30 is at the desired temperature for the SAGD Facility.
Reference numeral 22, HP Steam, from reference numeral 21, is more than enough for a SAGD Facility operating at a 3:1 steam to oil ratio, without co-injecting the flue gas.
Therefore, stream 22 is split into reference numeral 23, reference numeral 25, and reference numeral 26. Reference numeral 23 is used in reference numeral 14, the Oxygen Preheater, to preheat the oxygen to the desired temperature. Reference Page 7 of 10 numeral 25 is the amount of steam needed for the SAGD Injection Wells less the steam contained in reference numeral 29, the flue gas. Reference numeral 26 is the excess HP steam available for clean electric power generation. Based on a 3:1 steam to oil ratio, without the steam generated by the combustion of the asphaltenes, the amount of excess HP Steam is about 15%. Therefore, a significant amount of electricity can be generated by using the HP Steam in reference numeral 26. Reference numeral 25 is blended with reference numeral 29 to make reference numeral 30, the amount of HP
Steam/Flue gas needed to produce amount of bitumen needed to recover the asphaltenes in reference numeral 11.
Page 8 of 10
steam to remove 2.8% SO2 and NO2.
Page 5 of 10 BRIEF DESCRIPTION OF THE INVENTION
In accordance with present invention, at an existing Steam Assisted Gravity Drainage (SAGD) Facility, asphaltenes in their hot, liquid form are pumped to an asphaltene combustor shown in Fig. 3 that is very similar to the gasification reactor in a gasification unit. Steam is used to help distribute the asphaltenes into the combustion zone. Liquid oxygen is also pumped to the asphaltene combustor in order to minimize the amount of NO2 that is sequestered in the top of the reservoir. The flue gas from the asphaltene combustor is cooled in the Flue Gas Effluent Cooler very similar to the syngas effluent cooler in a gasification unit. The Flue Gas Effluent Cooler transfers heat from the flue gas to boiler feed water in order to produce steam at the pressure required for the injection well. Due to approach temperatures, the flue gas will still be at a higher temperature than the high pressure steam. Therefore, the flue gas exiting the Flue Gas Effluent Cooler is further cooled by exchanging heat with the boiler feed water that is being sent to the Flue Gas Effluent Cooler, after an amine has been added in order to prevent acidic corrosion in the heat exchange with the boiler feed water or in the lines to the reservoir.
By combusting the asphaltenes in this manner, the water that is a byproduct of the full combustion, is already mixed with the CO2, SO2, and NO2 that are also byproducts of the full combustion. Then the flue gas mixture is mixed with the steam that is going to the SAGD Injection wells.
Page 6 of 10 BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a graph showing the amount of CO2 produced for fuel sources available in Alberta. In addition it shows the CO2 released to the atmosphere when the BEST
Asphaltene Combustion Process is used to burn the asphaltenes;
FIG. 2 is a Typical Shell Residue Gasification Process Scheme showing that the Syngas is quenched to below the boiling point of water and the final combustion step is at a significantly lower pressure than the gasification reactor, so a compressor would be required to get the flue gas back up to the reservoir pressure;
FIG. 3 is a block diagram of the embodiment of the present invention for burning the asphaltenes to produce steam and ensuring that that the flue gas, including the steam byproduct of the combustion is at a sufficient pressure to mix with the steam going to the injection wells.
DETAILED DESCRIPTION
Referring now to FIG. 3, reference numeral 11 designates a typical asphaltene stream produced by a solvent deasphalting unit or an asphaltene removal unit, such as the BEST 1 Asphaltene Removal Unit, specifically designed for use at a Steam Assisted Gravity Drainage (SAGD) facility. Reference numeral 12 is steam that is used to help atomize the asphaltenes for combustion. Reference numeral 13 is liquid oxygen supplied by others that is preheated in reference numeral 14, the oxygen preheater.
Reference numeral 15, the preheated oxygen, is injected into reference numeral 16, the Asphaltene Combustor. Excess oxygen in the range from 1-4% of the amount needed for burning the asphaltenes to complete combustion, is used to ensure that there is complete combustion. Reference numeral 17, the flue gas, primarily CO2 and H20 that flows from reference numeral 16, the Asphaltene Combustor, to reference numeral 21, the Flue Gas Effluent Cooler. Reference numeral 18, pressurized boiler feed water is preheated in reference number 19, the Boiler Feed Water Preheater, by exchanging heat with reference numeral 27, the flue gas outlet from reference numeral 21.
Reference numeral 28, an amine stream, is added to reference numeral 27 before entering reference numeral 19 in order to prevent acidic attack resulting in corrosion in reference numeral 19 and all lines containing flue gas downstream of reference numeral 19. Reference numeral 29 is temperature controlled so that the temperature of reference numeral 30 is at the desired temperature for the SAGD Facility.
Reference numeral 22, HP Steam, from reference numeral 21, is more than enough for a SAGD Facility operating at a 3:1 steam to oil ratio, without co-injecting the flue gas.
Therefore, stream 22 is split into reference numeral 23, reference numeral 25, and reference numeral 26. Reference numeral 23 is used in reference numeral 14, the Oxygen Preheater, to preheat the oxygen to the desired temperature. Reference Page 7 of 10 numeral 25 is the amount of steam needed for the SAGD Injection Wells less the steam contained in reference numeral 29, the flue gas. Reference numeral 26 is the excess HP steam available for clean electric power generation. Based on a 3:1 steam to oil ratio, without the steam generated by the combustion of the asphaltenes, the amount of excess HP Steam is about 15%. Therefore, a significant amount of electricity can be generated by using the HP Steam in reference numeral 26. Reference numeral 25 is blended with reference numeral 29 to make reference numeral 30, the amount of HP
Steam/Flue gas needed to produce amount of bitumen needed to recover the asphaltenes in reference numeral 11.
Page 8 of 10
Claims (10)
1. A method for pressurized combustion of the asphaltenes removed from bitumen or extraheavy oil at the SAGD Central Processing Facility so that the flue gas can be co-injected with steam to produce bitumen or extraheavy oil, said method comprising:
a) pumping the asphaltenes into a pressurized vessel with oxygen for the combustion of the asphaltenes, b) combusting the asphaltenes to essentially full CO Combustion to CO2, so that the primary components of the combustion are CO2, H2O, SO2, and NO2, c) cooling the flue gas in a heat exchanger to convert boiler feed water to HP
Steam suitable for use in the SAGD Injection Wells, d) mixing the flue gas that has been used to exchange heat for steam generation with the HP steam created by cooling the flue gas from the combustion temperature to about 10-100 deg C above the temperature of the HP Steam, e) co-injecting the flue gas with the HP Steam being sent to the SAGD
Injection Wells, either for the production of bitumen or for the sequestration of the flue gas within the reservoir.
a) pumping the asphaltenes into a pressurized vessel with oxygen for the combustion of the asphaltenes, b) combusting the asphaltenes to essentially full CO Combustion to CO2, so that the primary components of the combustion are CO2, H2O, SO2, and NO2, c) cooling the flue gas in a heat exchanger to convert boiler feed water to HP
Steam suitable for use in the SAGD Injection Wells, d) mixing the flue gas that has been used to exchange heat for steam generation with the HP steam created by cooling the flue gas from the combustion temperature to about 10-100 deg C above the temperature of the HP Steam, e) co-injecting the flue gas with the HP Steam being sent to the SAGD
Injection Wells, either for the production of bitumen or for the sequestration of the flue gas within the reservoir.
2. A method according to claim 1 wherein injecting the oxygen into the pressurized vessel for the combustion of the asphaltenes includes:
a) a heat exchanger for preheating the oxygen for the combustion.
a) a heat exchanger for preheating the oxygen for the combustion.
3. A method according to claim 1 wherein injecting the oxygen into the pressurized vessel for the combustion of the asphaltenes includes:
a) a heat exchanger for preheating the oxygen for the combustion by cooling a portion of the HP Steam created by cooling the flue gas, or b) a heat exchanger for preheating the oxygen for the combustion by cooling either a portion of or the whole flue gas stream.
a) a heat exchanger for preheating the oxygen for the combustion by cooling a portion of the HP Steam created by cooling the flue gas, or b) a heat exchanger for preheating the oxygen for the combustion by cooling either a portion of or the whole flue gas stream.
4. A method according to claim 1 wherein cooling the flue gas includes:
a) a heat exchanger for preheating the boiler feed water used to cool the flue gas, and generation of the HP Steam.
a) a heat exchanger for preheating the boiler feed water used to cool the flue gas, and generation of the HP Steam.
5. A method according to claim 1 wherein cooling the flue gas includes:
a) a heat exchanger for preheating the boiler feed water by cooling a portion of the HP Steam created by cooling the flue gas, or b) a heat exchanger for preheating the boiler feed water by cooling either a portion of or the whole flue gas stream.
a) a heat exchanger for preheating the boiler feed water by cooling a portion of the HP Steam created by cooling the flue gas, or b) a heat exchanger for preheating the boiler feed water by cooling either a portion of or the whole flue gas stream.
6. A method according to claim 1 wherein cooling the flue gas includes:
a) injecting an amine downstream of the heat exchanger used to generate the HP Steam, or b) injecting any other inhibitor of acidic attack on carbon steel downstream of the heat exchanger used to generate the HP Steam.
a) injecting an amine downstream of the heat exchanger used to generate the HP Steam, or b) injecting any other inhibitor of acidic attack on carbon steel downstream of the heat exchanger used to generate the HP Steam.
7. A method according to claim 1 wherein mixing the flue gas with the HP Steam going to the SAGD Injection Wells includes:
a) a compressor for increasing the pressure of the flue gas up to the pressure required for mixing in the HP Steam going to the SAGD Injection well.
a) a compressor for increasing the pressure of the flue gas up to the pressure required for mixing in the HP Steam going to the SAGD Injection well.
8. A method according to claim 7 where one or more of the following are removed from the flue gas before the compressor:
a) water, H2O.
b) sulfur dioxide, SO2, or c) nitrogen dioxide, NO2,
a) water, H2O.
b) sulfur dioxide, SO2, or c) nitrogen dioxide, NO2,
9. A method according to claim 1 where the facility is not located at a SAGD Facility, but located where asphaltenes are available.
10. A method according to claim 8 where the facility is not located at a SAGD
Facility, but located where asphaltenes are available.
Facility, but located where asphaltenes are available.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2947365A CA2947365A1 (en) | 2016-11-03 | 2016-11-03 | Method of and apparatus for asphaltene combustion at the sagd central processing facility |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2947365A CA2947365A1 (en) | 2016-11-03 | 2016-11-03 | Method of and apparatus for asphaltene combustion at the sagd central processing facility |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2947365A1 true CA2947365A1 (en) | 2018-05-03 |
Family
ID=62068361
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2947365A Abandoned CA2947365A1 (en) | 2016-11-03 | 2016-11-03 | Method of and apparatus for asphaltene combustion at the sagd central processing facility |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2947365A1 (en) |
-
2016
- 2016-11-03 CA CA2947365A patent/CA2947365A1/en not_active Abandoned
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