CA2917909C - Electric and fired steam generation systems - Google Patents
Electric and fired steam generation systems Download PDFInfo
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- CA2917909C CA2917909C CA2917909A CA2917909A CA2917909C CA 2917909 C CA2917909 C CA 2917909C CA 2917909 A CA2917909 A CA 2917909A CA 2917909 A CA2917909 A CA 2917909A CA 2917909 C CA2917909 C CA 2917909C
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- 239000007789 gas Substances 0.000 claims abstract description 31
- 238000000034 method Methods 0.000 claims abstract description 28
- 238000002347 injection Methods 0.000 claims abstract description 25
- 239000007924 injection Substances 0.000 claims abstract description 25
- 238000011084 recovery Methods 0.000 claims abstract description 22
- 230000005611 electricity Effects 0.000 claims abstract description 17
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims abstract description 12
- 239000003546 flue gas Substances 0.000 claims abstract description 12
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims description 24
- 229910002092 carbon dioxide Inorganic materials 0.000 claims description 12
- 239000001569 carbon dioxide Substances 0.000 claims description 12
- 238000002485 combustion reaction Methods 0.000 claims description 10
- 239000000203 mixture Substances 0.000 claims description 8
- 239000007800 oxidant agent Substances 0.000 claims description 7
- 230000001590 oxidative effect Effects 0.000 claims description 7
- 230000009977 dual effect Effects 0.000 claims description 6
- 238000010796 Steam-assisted gravity drainage Methods 0.000 claims description 5
- 230000015572 biosynthetic process Effects 0.000 claims description 4
- 239000012808 vapor phase Substances 0.000 claims description 4
- 244000126002 Ziziphus vulgaris Species 0.000 claims 1
- 238000010438 heat treatment Methods 0.000 claims 1
- 239000003921 oil Substances 0.000 description 15
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 8
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 7
- 239000003570 air Substances 0.000 description 6
- 238000004519 manufacturing process Methods 0.000 description 6
- 239000000446 fuel Substances 0.000 description 5
- 238000009833 condensation Methods 0.000 description 4
- 230000005494 condensation Effects 0.000 description 4
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 3
- 239000003345 natural gas Substances 0.000 description 3
- 229910052760 oxygen Inorganic materials 0.000 description 3
- 239000001301 oxygen Substances 0.000 description 3
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 239000007788 liquid Substances 0.000 description 2
- 238000010794 Cyclic Steam Stimulation Methods 0.000 description 1
- 238000010795 Steam Flooding Methods 0.000 description 1
- 238000010793 Steam injection (oil industry) Methods 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 239000012080 ambient air Substances 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 239000010426 asphalt Substances 0.000 description 1
- -1 asphaltenes Natural products 0.000 description 1
- 230000033228 biological regulation Effects 0.000 description 1
- 238000009835 boiling Methods 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 239000000295 fuel oil Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 239000012528 membrane Substances 0.000 description 1
- 239000002006 petroleum coke Substances 0.000 description 1
- 238000010248 power generation Methods 0.000 description 1
- 238000005201 scrubbing Methods 0.000 description 1
- 230000009919 sequestration Effects 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 238000001179 sorption measurement Methods 0.000 description 1
- 238000004326 stimulated echo acquisition mode for imaging Methods 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
- 230000000153 supplemental effect Effects 0.000 description 1
Classifications
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
- F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
- F01K17/00—Using steam or condensate extracted or exhausted from steam engine plant
- F01K17/04—Using steam or condensate extracted or exhausted from steam engine plant for specific purposes other than heating
-
- 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
- F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
- F01K—STEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
- F01K23/00—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids
- F01K23/02—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled
- F01K23/06—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle
- F01K23/10—Plants characterised by more than one engine delivering power external to the plant, the engines being driven by different fluids the engine cycles being thermally coupled combustion heat from one cycle heating the fluid in another cycle with exhaust fluid of one cycle heating the fluid in another cycle
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F22—STEAM GENERATION
- F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
- F22B1/00—Methods of steam generation characterised by form of heating method
- F22B1/28—Methods of steam generation characterised by form of heating method in boilers heated electrically
-
- 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
- Y02E20/16—Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mechanical Engineering (AREA)
- Combustion & Propulsion (AREA)
- General Engineering & Computer Science (AREA)
- Chemical & Material Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Sustainable Development (AREA)
- Sustainable Energy (AREA)
- Thermal Sciences (AREA)
- Engine Equipment That Uses Special Cycles (AREA)
Abstract
Methods and systems relate to steam assisted oil recovery utilizing a fired boiler and an electric boiler, which may be disposed closer to an injection well than the fired boiler. A gas turbine produces electricity supplied to the electric boiler and flue gas exhaust that may input into the fired boiler. The electric boiler may vaporize condensate that forms from the steam generated in the fired boiler prior to being introduced into the injection well.
Description
ELECTRIC AND FIRED STEAM GENERATION SYSTEMS
FIELD OF THE INVENTION
[0001]
Embodiments of the invention relate to generating steam for steam assisted production of hydrocarbons with a fired boiler and an electric boiler.
BACKGROUND OF THE INVENTION
FIELD OF THE INVENTION
[0001]
Embodiments of the invention relate to generating steam for steam assisted production of hydrocarbons with a fired boiler and an electric boiler.
BACKGROUND OF THE INVENTION
[0002]
Recovery of heavy oil reserves often requires use of high quality steam to heat and mobilize the oil through processes such as steam assisted gravity drainage (SAGD).
Energy intensive steam generators, such as once through steam generators (OTSGs), produce the steam often conveyed from a central processing facility to multiple wells for injection. For example, distances of up to ten kilometers may separate well pads from the steam generators.
Recovery of heavy oil reserves often requires use of high quality steam to heat and mobilize the oil through processes such as steam assisted gravity drainage (SAGD).
Energy intensive steam generators, such as once through steam generators (OTSGs), produce the steam often conveyed from a central processing facility to multiple wells for injection. For example, distances of up to ten kilometers may separate well pads from the steam generators.
[0003] Heat losses in steam lines and pressure let-down at such well pads results in condensation of about five percent of the steam. Prior approaches to compensate for the condensation at the well pads rely on oversizing the steam generators and water treatment systems. However, the oversizing adds to costs while providing an inefficient process.
[0004] The oil reserves recovered with the steam often exist in cold climates contributing to the heat losses. Temperature variations throughout a year create additional problems with determining desired steam demand since condensation levels may fluctuate. Further, the heat losses may limit how far the central processing facility may be from the well pads.
[0005]
Therefore, a need exists for systems and methods that provide cost efficient injection quality steam at the well pad.
BRIEF SUMMARY OF THE DISCLOSURE
Therefore, a need exists for systems and methods that provide cost efficient injection quality steam at the well pad.
BRIEF SUMMARY OF THE DISCLOSURE
[0006] In one embodiment, a method of steam assisted oil recovery with dual steam generation includes producing electricity with an onsite gas turbine, generating steam with a fired boiler at a first location and conveying the steam to a second location resulting in a mixture formed of the steam and condensate caused by heat loss during the conveying. Upon separating the steam from the condensate in the mixture, an electric boiler powered by the electricity from the gas turbine heats the condensate to convert the condensate back to a vapor phase combined with the steam separated from the condensate to provide a combined steam flow. The method further includes introducing the combined steam flow into a formation for the steam assisted oil recovery.
[0007] According to one embodiment, a method of steam assisted oil recovery with dual steam generation includes producing electricity with an onsite gas turbine, generating steam with both a fired boiler coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler and an electric boiler powered by the electricity from the gas turbine. Introducing the steam from the fired boiler and the electric boiler into at least one injection well enables the steam assisted oil recovery.
[0008] For one embodiment, a system for steam assisted oil recovery with dual steam generation includes an onsite gas turbine to produce electricity, a fired boiler to generate steam at a first location and a steam conduit coupled to the fired boiler for conveying the steam to a second location. A separator couples to the steam conduit for dividing the steam from condensate formed by heat loss along the steam conduit and feeds the condensate to an electric boiler powered by the electricity from the gas turbine to heat and convert the condensate back to a vapor phase. An injection well couples to vapor outputs from the separator and the electric boiler for the steam assisted oil recovery.
BRIEF DESCRIPTION OF THE DRAWINGS
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] A more complete understanding of the present invention and benefits thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings in which:
[0010] Figure 1 is a schematic of a production system for steam assisted oil recovery utilizing a fired boiler and an electric boiler disposed closer to an injection well than the fired boiler, according to one embodiment of the invention.
DETAILED DESCRIPTION
DETAILED DESCRIPTION
[0011] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.
[0012] Methods and systems relate to steam assisted oil recovery utilizing a fired boiler and an electric boiler, which may be disposed closer to an injection well than the fired boiler. A gas turbine produces electricity supplied to the electric boiler and flue gas exhaust that may input into the fired boiler. The electric boiler may vaporize condensate that forms from the steam generated in the fired boiler prior to being introduced into the injection well.
[0013] Figure 1 illustrates an exemplary system that includes a gas turbine 100, a fired boiler 102, a separator 104, an electric boiler 106, an injection well 108 and a production well 110. While illustrated in an exemplary SAGD configuration, other techniques, such as cyclic steam stimulation, solvent assisted SAGD, steam drive or huff and puff, may employ the steam generated as described herein. The injection well 108 extends in a horizontal direction and above the production well 110 also extending in the horizontal direction.
[0014] In operation, steam generated by the boilers 102, 106 enters a formation along the injection well 108 forming a steam chamber with heat transferred from the steam to oil or bitumen in the formation. The oil once heated becomes less viscous and mobile enough for flowing by gravity along with condensate of the steam to the production well 110. A mixture of the condensate and oil collected in the production well 110 flows to surface where the oil to be sold is removed from recovered water, which is recycled for generating additional steam to sustain steam injection.
[0015] The gas turbine 100 combusts fuel, such as natural gas, with an oxidant, such as air, to drive an electrical generator. In some embodiments, the gas turbine operates at a central processing facility of an oil recovery site to at least generate electricity for the electric boiler 106. The gas turbine 100 may also provide other electricity requirements for the site.
[0016] The fired boiler 102, such as a once through steam generator, may also operate at the central processing facility and receives fuel and an oxidant supply for combustion at a burner to heat water that is input. At least part of the water converts to the steam that may have a quality of at least seventy-five percent and may be separated from remaining liquid blowdown prior to being conveyed to the injection well 108. The pressure of the steam generated by the fired boiler 102 in some embodiments ranges from 5000 kilopascals (kPa) to 11,000 kPa and is selected depending on desired injection pressure with accounting for pressure losses when conveyed to the injection well 108.
[0017] For some embodiments, flue gas exhaust from the gas turbine 100 passes to the fired boiler 102 where the exhaust is used as at least part of the oxidant supply to the fired boiler 102. The gas turbine 100 operates at excess air input levels such that the exhaust may contain 12-15 volume percent oxygen, which may be high enough to support combustion in the fired boiler 102. Depending on power requirements and flow rates, the fired boiler 102 may use supplemental air to fully oxidize the fuel that may include hydrocarbons, such as coal, petroleum coke, asphaltenes, methane or natural gas.
[0018] The separator 104 located proximate the injection well 108 at a well pad couples to the fired boiler 102 via a steam conduit to receive a mixture of the steam from the fired boiler 102 and condensate resulting from pressure let-down and heat loss along the steam conduit. Outputs from the separator 104 divide the mixture to direct the steam (e.g., at 100 percent quality) into the injection well 108 and the condensate to the electric boiler 106. The separator 104 ensures desired quality of the steam is injected since the separator 104 may be within 100 meters of the injection well 108 compared to the central processing facility with the fired boiler 102 that may be greater than 100 meters or greater than 1 kilometer from the injection well 108.
[0019] The electric boiler 106 heats the condensate and may be located at the well pad and within 100 meters of the injection well 108. The condensate thereby converts back to steam for output by the electric boiler 106. The steam from the electric boiler 106 combines with the steam output from the separator 104 prior to introduction into the injection well 108.
[0020]
Provided remote location, typical lack of fuel supply and limited space at the well pad, the electric boiler 106 benefits from not requiring fuel lines, combustion air blowers and stacks. Further, the electric boiler 106 provides efficient conversion of the condensate into the steam since substantially all input electrical energy transfers to the condensate. Combustion-based steam generation in contrast to the electric boiler 106 fails to benefit from near boiling temperatures (e.g., 300 C) of the condensate since such high preheat leads to higher flue gas exit temperatures, thereby reducing efficiency.
Provided remote location, typical lack of fuel supply and limited space at the well pad, the electric boiler 106 benefits from not requiring fuel lines, combustion air blowers and stacks. Further, the electric boiler 106 provides efficient conversion of the condensate into the steam since substantially all input electrical energy transfers to the condensate. Combustion-based steam generation in contrast to the electric boiler 106 fails to benefit from near boiling temperatures (e.g., 300 C) of the condensate since such high preheat leads to higher flue gas exit temperatures, thereby reducing efficiency.
[0021] The gas turbine 100 electrical power output increases with decreasing air inlet temperature due to the higher density of the inlet air. For example, the gas turbine 100 provides twenty percent more power output at -18 C than at 15 C. As ambient air temperature decreases, heat losses in the steam conduit between the fired boiler 102 at the central processing facility and the separator 104 at the well pad increase resulting in more condensation losses. Relative higher loads on the electric boiler 106 thus coincide with when the gas turbine 100, since located onsite and exposed to like temperatures, generates additional power during colder periods. Expense of producing such additional power during the colder periods requires no additional capital costs.
[0022]
Further, generating the steam at the well pad extends possible distance between the well pad and the central processing facility since not limited by such heat loss along the steam conduit. For some embodiments, well pads closer to the central processing facility may rely on the fired boiler 102 alone for generation of the steam to be injected without utilizing the electric boiler 106 that is only employed for well pads having a relative further distance from the central processing facility. The electric boiler 106 may be selected for example to convert the condensate to steam at well pads greater than five kilometers from the central processing facility or that have at least five percent of the steam condensed upon reaching such well pads while condensate from other well pads is recycled or otherwise used remote therefrom.
Further, generating the steam at the well pad extends possible distance between the well pad and the central processing facility since not limited by such heat loss along the steam conduit. For some embodiments, well pads closer to the central processing facility may rely on the fired boiler 102 alone for generation of the steam to be injected without utilizing the electric boiler 106 that is only employed for well pads having a relative further distance from the central processing facility. The electric boiler 106 may be selected for example to convert the condensate to steam at well pads greater than five kilometers from the central processing facility or that have at least five percent of the steam condensed upon reaching such well pads while condensate from other well pads is recycled or otherwise used remote therefrom.
[0023] Some embodiments may employ the electric boiler 106 input with electricity from the gas turbine 100 and water conveyed in liquid form from the central processing facility instead of the separator 104 coupled to the fired boiler 102. The water may pass to electric well pad boilers (such as the electric boiler 106) for one or more well pads forming a distal pad set further from the central processing facility than one or more well pads forming a proximal pad set, which is provided with steam that is from the central processing facility and may be the mixture of wet steam as described herein upon reaching even the proximal pad set. The fired boiler 102 at the central processing facility thus alone or in combination with the electric boiler 106 may supply steam requirements for the proximal pad set while well pad electric boilers alone may generate all steam required for the distal pad set.
[0024] In some embodiments, flue gas exiting the fired boiler 102 contains 2-4 volume percent oxygen and 8-10 volume percent carbon dioxide. These concentrations may facilitate implementing a carbon dioxide recovery unit 112 if desired or necessary to meet government regulations. For example, an amine-based scrubbing unit, a hybrid adsorption/cryogenic capture unit, or a hybrid membrane/cryogenic capture unit may strip the carbon dioxide from the flue gas of the fired boiler 102 and provide a suitable output for sequestration.
[0025] Carbon dioxide capture from stand-alone gas turbines proves difficult because of relative lower carbon dioxide levels and higher oxygen levels, which have an adverse effect on carbon dioxide recovery units. However, the carbon dioxide produced in the gas turbine 100 passes along with the carbon dioxide from the fired boiler 102 for subsequent capture. Further, the gas turbine 100 operates in simple cycle mode, which is lower in capital cost than alternate power generation options such as natural gas combined cycle (NGCC) plants that require additional equipment such as a heat recovery steam generator (HRSG), steam turbines, a condenser, a cooling system and a water treatment system.
[0026] In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as additional embodiments of the present invention.
[0027]
Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the scope of the invention as defined by the following claims.
Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein.
It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.
Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the scope of the invention as defined by the following claims.
Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein.
It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.
Claims (22)
1. A method of steam assisted oil recovery with dual steam generation, comprising:
producing electricity with an onsite gas turbine;
generating steam with both a fired boiler coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler and an electric boiler powered by the electricity from the gas turbine; and introducing the steam from the fired boiler and the electric boiler into at least one injection well for the steam assisted oil recovery.
producing electricity with an onsite gas turbine;
generating steam with both a fired boiler coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler and an electric boiler powered by the electricity from the gas turbine; and introducing the steam from the fired boiler and the electric boiler into at least one injection well for the steam assisted oil recovery.
2. The method according to claim 1, wherein the fired boiler alone supplies steam requirements for one or more well pads forming a proximal pad set closer to the fired boiler than one or more well pads forming a distal pad set that includes the electric boiler.
3. The method according to claim 1 or 2, wherein the fired boiler is at least 0.5 kilometers from the electric boiler.
4. The method according to claim 3, wherein the fired boiler is between 0.5km and 10km from the electric boiler.
5. A method of steam assisted oil recovery with dual steam generation, comprising:
producing electricity with an onsite gas turbine;
generating steam with the fired boiler at a first location, wherein the fired boiler is coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler;
conveying the steam to a second location resulting in a mixture formed of the steam and condensate caused by heat loss during the conveying;
separating the steam from the condensate in the mixture;
heating the condensate in an electric boiler powered by electricity from the gas Date Recue/Date Received 2020-12-08 turbine to convert the condensate back to a vapor phase combined with the steam separated from the condensate to provide a combined steam flow; and introducing the combined steam flow into a formation for the steam assisted oil recovery.
producing electricity with an onsite gas turbine;
generating steam with the fired boiler at a first location, wherein the fired boiler is coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler;
conveying the steam to a second location resulting in a mixture formed of the steam and condensate caused by heat loss during the conveying;
separating the steam from the condensate in the mixture;
heating the condensate in an electric boiler powered by electricity from the gas Date Recue/Date Received 2020-12-08 turbine to convert the condensate back to a vapor phase combined with the steam separated from the condensate to provide a combined steam flow; and introducing the combined steam flow into a formation for the steam assisted oil recovery.
6. The method according to claim 5, further comprising capturing carbon dioxide from a flue gas exhaust of the fired boiler.
7. The method according to claim 5, wherein carbon dioxide is captured from combustion products of the fired boiler.
8. The method according to any one of claims 5 to 7, wherein the electric boiler is disposed within 100 meters of where the combined steam flow is introduced into a well and the fired boiler is located further than 100 meters from the well.
9. The method according to claim 8, wherein the fired boiler is located between 100 meters and 10,000 meters from the well.
10. The method according to any one of claims 5 to 9, wherein the fired boiler is a once through steam generator.
11. The method according to any one of claims 5 to 10, wherein the condensate enters the electric boiler at a temperature of at least 300 C.
12. The method according to claim 11, wherein the condensate enters the electric boiler at a temperature of between 300 C and 1,000 C.
Date Recue/Date Received 2020-12-08
Date Recue/Date Received 2020-12-08
13. The method according to claim 5, wherein the fired boiler at the first location is at least 0.5 kilometers from the second location and the electric boiler.
14. The method of claim 13, wherein the fired boiler at the first location is between 0.5 kilometers and 10 kilometers from the second location and the electric boiler.
15. The method according to any one of claims 5 to 14, wherein the steam assisted oil recovery is a steam assisted gravity drainage process.
16. The method according to any one of claims 5 to 15, wherein the fired boiler alone supplies steam requirements for one or more well pads forming a proximal pad set closer to the fired boiler than one or more well pads forming a distal pad set that includes the electric boiler.
17. A system for performing a method of steam assisted oil recovery with dual steam generation, comprising:
an onsite gas turbine to produce electricity;
a fired boiler to generate steam at a first location, wherein the fired boiler is coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler;
a steam conduit coupled to the fired boiler for conveying the steam to a second location;
a separator coupled to the steam conduit for dividing the steam from condensate formed by heat loss along the steam conduit;
an electric boiler powered by the electricity from the gas turbine to heat and convert the condensate back to a vapor phase; and an injection well coupled to vapor outputs from the separator and the electric boiler for the steam assisted oil recovery.
Date Recue/Date Received 2020-12-08
an onsite gas turbine to produce electricity;
a fired boiler to generate steam at a first location, wherein the fired boiler is coupled to use a flue gas exhaust of the gas turbine as an oxidant feed for combustion in the fired boiler;
a steam conduit coupled to the fired boiler for conveying the steam to a second location;
a separator coupled to the steam conduit for dividing the steam from condensate formed by heat loss along the steam conduit;
an electric boiler powered by the electricity from the gas turbine to heat and convert the condensate back to a vapor phase; and an injection well coupled to vapor outputs from the separator and the electric boiler for the steam assisted oil recovery.
Date Recue/Date Received 2020-12-08
18. The system according to claim 17, further comprising a recovery unit to capture carbon dioxide from a flue gas exhaust of the fired boiler.
19. The system of claim 17 or 18, wherein carbon dioxide is captured from combustion products of the fired boiler.
20. The system according to any one of claims 17 to 19, wherein the electric boiler is disposed within 100 meters of the injection well and the fired boiler is located further than 100 meters from the injection well.
21. The system according to any one of claims 17 to 20, wherein the fired boiler is a once through steam generator.
22. The system according to any one of claim 17 to 21, wherein the fired boiler at the first location is at least 0.5 kilometers from the second location and the electric boiler.
Date Recue/Date Received 2020-12-08
Date Recue/Date Received 2020-12-08
Applications Claiming Priority (5)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US201361856275P | 2013-07-19 | 2013-07-19 | |
| US61/856,275 | 2013-07-19 | ||
| US14/334,884 US20150021031A1 (en) | 2013-07-19 | 2014-07-18 | Electric and fired steam generation systems |
| PCT/US2014/047203 WO2015010025A1 (en) | 2013-07-19 | 2014-07-18 | Electric and fired steam generation systems |
| US14/334,884 | 2014-07-18 |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2917909A1 CA2917909A1 (en) | 2015-01-22 |
| CA2917909C true CA2917909C (en) | 2021-05-11 |
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Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2917909A Active CA2917909C (en) | 2013-07-19 | 2014-07-18 | Electric and fired steam generation systems |
Country Status (3)
| Country | Link |
|---|---|
| US (1) | US20150021031A1 (en) |
| CA (1) | CA2917909C (en) |
| WO (1) | WO2015010025A1 (en) |
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| KR101744724B1 (en) * | 2015-03-19 | 2017-06-08 | 현대자동차주식회사 | Audio navigation device, vehicle having the same, user device, and method for controlling vehicle |
| US10247409B2 (en) | 2015-11-04 | 2019-04-02 | Conocophillips Company | Remote preheat and pad steam generation |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6200128B1 (en) * | 1997-06-09 | 2001-03-13 | Praxair Technology, Inc. | Method and apparatus for recovering sensible heat from a hot exhaust gas |
| US6531516B2 (en) * | 2001-03-27 | 2003-03-11 | Exxonmobil Research & Engineering Co. | Integrated bitumen production and gas conversion |
| WO2007098239A2 (en) * | 2006-02-21 | 2007-08-30 | Clean Energy Systems, Inc. | Hybrid oxy-fuel combustion power process |
| US9097110B2 (en) * | 2010-12-03 | 2015-08-04 | Exxonmobil Upstream Research Company | Viscous oil recovery using a fluctuating electric power source and a fired heater |
| US20120222426A1 (en) * | 2011-03-04 | 2012-09-06 | Conocophillips Company | Integrated gas turbine, sagd boiler and carbon capture |
-
2014
- 2014-07-18 WO PCT/US2014/047203 patent/WO2015010025A1/en active Application Filing
- 2014-07-18 CA CA2917909A patent/CA2917909C/en active Active
- 2014-07-18 US US14/334,884 patent/US20150021031A1/en not_active Abandoned
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|---|---|
| US20150021031A1 (en) | 2015-01-22 |
| WO2015010025A1 (en) | 2015-01-22 |
| CA2917909A1 (en) | 2015-01-22 |
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