CA2233057A1 - Produced water and light hydrocarbon liquid vapor injection method and apparatus - Google Patents
Produced water and light hydrocarbon liquid vapor injection method and apparatus Download PDFInfo
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- CA2233057A1 CA2233057A1 CA 2233057 CA2233057A CA2233057A1 CA 2233057 A1 CA2233057 A1 CA 2233057A1 CA 2233057 CA2233057 CA 2233057 CA 2233057 A CA2233057 A CA 2233057A CA 2233057 A1 CA2233057 A1 CA 2233057A1
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- 239000007788 liquid Substances 0.000 title claims abstract description 147
- 238000000034 method Methods 0.000 title claims abstract description 67
- 238000002347 injection Methods 0.000 title claims abstract description 30
- 239000007924 injection Substances 0.000 title claims abstract description 30
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims description 111
- 150000002430 hydrocarbons Chemical class 0.000 title claims description 109
- 229930195733 hydrocarbon Natural products 0.000 title claims description 106
- 239000004215 Carbon black (E152) Substances 0.000 title claims description 89
- 239000000203 mixture Substances 0.000 claims abstract description 49
- 238000010438 heat treatment Methods 0.000 claims abstract description 28
- 238000002156 mixing Methods 0.000 claims abstract description 10
- 239000003921 oil Substances 0.000 claims description 116
- 239000010779 crude oil Substances 0.000 claims description 86
- 238000004519 manufacturing process Methods 0.000 claims description 58
- 239000012530 fluid Substances 0.000 claims description 46
- 239000007787 solid Substances 0.000 claims description 27
- 239000012071 phase Substances 0.000 claims description 21
- 239000012808 vapor phase Substances 0.000 claims description 11
- 230000003134 recirculating effect Effects 0.000 claims description 7
- 238000000926 separation method Methods 0.000 claims description 6
- 238000003860 storage Methods 0.000 claims description 4
- 238000005086 pumping Methods 0.000 claims 3
- 239000010724 circulating oil Substances 0.000 claims 1
- 239000007789 gas Substances 0.000 description 15
- 238000011084 recovery Methods 0.000 description 10
- 238000010793 Steam injection (oil industry) Methods 0.000 description 9
- 238000005260 corrosion Methods 0.000 description 8
- 230000007797 corrosion Effects 0.000 description 8
- 238000011033 desalting Methods 0.000 description 7
- 230000015572 biosynthetic process Effects 0.000 description 6
- 239000007791 liquid phase Substances 0.000 description 6
- 230000005484 gravity Effects 0.000 description 4
- 239000011347 resin Substances 0.000 description 4
- 229920005989 resin Polymers 0.000 description 4
- 150000003839 salts Chemical class 0.000 description 4
- 238000010796 Steam-assisted gravity drainage Methods 0.000 description 3
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 3
- 229910052500 inorganic mineral Inorganic materials 0.000 description 3
- 239000011707 mineral Substances 0.000 description 3
- 239000001301 oxygen Substances 0.000 description 3
- 229910052760 oxygen Inorganic materials 0.000 description 3
- 239000000126 substance Substances 0.000 description 3
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 2
- -1 Gabon dioxide Chemical compound 0.000 description 2
- 238000010795 Steam Flooding Methods 0.000 description 2
- 239000000470 constituent Substances 0.000 description 2
- 238000001816 cooling Methods 0.000 description 2
- 125000004122 cyclic group Chemical group 0.000 description 2
- 230000001419 dependent effect Effects 0.000 description 2
- 238000004945 emulsification Methods 0.000 description 2
- 239000000839 emulsion Substances 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 239000003673 groundwater Substances 0.000 description 2
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 2
- 238000005342 ion exchange Methods 0.000 description 2
- 230000001105 regulatory effect Effects 0.000 description 2
- GEHJYWRUCIMESM-UHFFFAOYSA-L sodium sulfite Chemical compound [Na+].[Na+].[O-]S([O-])=O GEHJYWRUCIMESM-UHFFFAOYSA-L 0.000 description 2
- 239000002352 surface water Substances 0.000 description 2
- 230000008016 vaporization Effects 0.000 description 2
- 241000894006 Bacteria Species 0.000 description 1
- 241000195493 Cryptophyta Species 0.000 description 1
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 1
- 229910021536 Zeolite Inorganic materials 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- 239000003085 diluting agent Substances 0.000 description 1
- HNPSIPDUKPIQMN-UHFFFAOYSA-N dioxosilane;oxo(oxoalumanyloxy)alumane Chemical compound O=[Si]=O.O=[Al]O[Al]=O HNPSIPDUKPIQMN-UHFFFAOYSA-N 0.000 description 1
- 230000009977 dual effect Effects 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 238000001704 evaporation Methods 0.000 description 1
- 238000010304 firing Methods 0.000 description 1
- 239000013505 freshwater Substances 0.000 description 1
- 125000001183 hydrocarbyl group Chemical group 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 239000011261 inert gas Substances 0.000 description 1
- 239000003112 inhibitor Substances 0.000 description 1
- 150000002500 ions Chemical class 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 150000002739 metals Chemical class 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 238000005191 phase separation Methods 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 230000002000 scavenging effect Effects 0.000 description 1
- 150000004760 silicates Chemical class 0.000 description 1
- 229910052708 sodium Inorganic materials 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 235000010265 sodium sulphite Nutrition 0.000 description 1
- 238000009834 vaporization Methods 0.000 description 1
- 239000010457 zeolite Substances 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
A method and apparatus for producing, from a liquid, a vapor for injection into a well. The method includes the steps of combining a quantity of the liquid with a quantity of an oil to produce a mixture of liquid and oil, heating the mixture to produce from the liquid a quantity of the vapor, and separating the vapor from the oil. The apparatus includes a mixer for mixing the liquid and the oil, a heater for heating the mixture and a vapor separator for separating the vapor and the oil.
Description
42-28976.1-Disclosure PRODUCED WATER AND LIGHT HYDROCARBON LIOUID VAPOR IN~BCTION
METHOD AND APPARATUS
FIELD OF INVENTION
The present invention relates to a method and an apparatus for producing a vapor for injection into a well. The vapor is preferably produced from at least one of produced water and light hydrocarbon liquid obtained from a hydrocarbon production well.
BACKGROUND OF INVENTION
The oil and gas industry presently uses a variety of thermal recovery methods such as cyclic steam injection, steam drive and steam assisted gravity drainage (SAGD) to produce hydrocarbons, and in particular crude oil, from hydrocarbon producing wells. These thermal recovery methods are most commonly used in oil reservoirs where the oil is of low to medium gravity and the viscosity is high. The viscosity of oil decreases rapidly with increases in temperature. This is particularly dramatic with low gravity crude oils.
Heating the oil in-situ with high temperature steam injection has been found to be highly effective in increasing the mobility of the oil. As a result of the steam injection, the oil flows more readily by gravity or by one or more other driving mechanisms to the production well, where it flows or is pumped to the surface.
Conventionally, these thermal recovery methods utilize steam injection into the wellbore. More particularly, the steam is typically produced by a once through or single pass water tube steam boiler. A feedwater pump pressures the feedwater to the required pressure level and forces it through the steam boiler piping or tubing that surrounds the gas or oil fired burners. The feedwater is heated, vaporized and forced directly down the steam injection well. Typically, the steam boiler converts approximately 80% by weight of the feedwater to steam. The remaining 20% by weight of the feedwater is left as a liquid to carry any solids in the feedwater and to inhibit their deposition on the tube walls of the steam boiler.
Deposited solids or scale tend to insulate the tube walls and reduce any heat transfer therethrough. This locally reduced heat transfer allows the flame from the burners of the steam boiler to heat the tubing to extreme high temperatures, which may result in a tube rupture.
Although 20% by weight of the feedwater is left as liquid to carry any solids, it is still necessary when utilizing conventional steam injection processes and equipment to utilize feedwater with a hardness of substantially zero in order to substantially prevent or significantly inhibit any scaling. Thus, the hardness of the feedwater must often be reduced prior to its use by softening or otherwise pretreating the feedwater. Ion exchange softeners are commonly used for this purpose. Ion exchange softeners are typically a train-connected, dual bank cationic-exchange resin system, using zeolite as the resin. The beds are alternatingly regenerated with sodium cloride. In addition, water used in steam generaters must typically be free of corrosive gases such as oxygen, Gabon dioxide, and hydrogen sulfide. Otherwise, the corrosive gases can cause corrosion to the hot, water wet, inner surface of the tubes in the steam generater. Various chemicals including sodium sulfite are typically used to scavenge the oxygen and thus limit corrosion.
Large quantities of feedwater are typically required for the operation of conventional thermal recovery or steam injection processes and equipment.
However, as discussed above, large quantities or sources of good quality feedwater are difficult to find. Surface water may be obtained from either lakes or rivers, however, this water may contain silt, bacteria, algae, dissolved minerals and gases.
Water from these sources tends to require filtering in order to remove any undissolved solids and to prevent fouling of the resin beds of the wafer softeners.
Fresh ground water produced from wells may not require filtering but tends to be higher in total dissolved minerals or solids (TDS). As well, the use of both surface water and fresh ground water from wells is restricted by government environmental agencies. Higher TDS water from deeper wells may be used but capital and operating costs to treat the water tend to increase with TDS
content and hardness. Water produced with crude oil (referred to as "produced water") tends to be even more difficult to treat since it usually contains oil fines and has a high mineral content. Thus, care must be taken first to remove any oil or hydrogen sulfide or it may foul the softener resins.
METHOD AND APPARATUS
FIELD OF INVENTION
The present invention relates to a method and an apparatus for producing a vapor for injection into a well. The vapor is preferably produced from at least one of produced water and light hydrocarbon liquid obtained from a hydrocarbon production well.
BACKGROUND OF INVENTION
The oil and gas industry presently uses a variety of thermal recovery methods such as cyclic steam injection, steam drive and steam assisted gravity drainage (SAGD) to produce hydrocarbons, and in particular crude oil, from hydrocarbon producing wells. These thermal recovery methods are most commonly used in oil reservoirs where the oil is of low to medium gravity and the viscosity is high. The viscosity of oil decreases rapidly with increases in temperature. This is particularly dramatic with low gravity crude oils.
Heating the oil in-situ with high temperature steam injection has been found to be highly effective in increasing the mobility of the oil. As a result of the steam injection, the oil flows more readily by gravity or by one or more other driving mechanisms to the production well, where it flows or is pumped to the surface.
Conventionally, these thermal recovery methods utilize steam injection into the wellbore. More particularly, the steam is typically produced by a once through or single pass water tube steam boiler. A feedwater pump pressures the feedwater to the required pressure level and forces it through the steam boiler piping or tubing that surrounds the gas or oil fired burners. The feedwater is heated, vaporized and forced directly down the steam injection well. Typically, the steam boiler converts approximately 80% by weight of the feedwater to steam. The remaining 20% by weight of the feedwater is left as a liquid to carry any solids in the feedwater and to inhibit their deposition on the tube walls of the steam boiler.
Deposited solids or scale tend to insulate the tube walls and reduce any heat transfer therethrough. This locally reduced heat transfer allows the flame from the burners of the steam boiler to heat the tubing to extreme high temperatures, which may result in a tube rupture.
Although 20% by weight of the feedwater is left as liquid to carry any solids, it is still necessary when utilizing conventional steam injection processes and equipment to utilize feedwater with a hardness of substantially zero in order to substantially prevent or significantly inhibit any scaling. Thus, the hardness of the feedwater must often be reduced prior to its use by softening or otherwise pretreating the feedwater. Ion exchange softeners are commonly used for this purpose. Ion exchange softeners are typically a train-connected, dual bank cationic-exchange resin system, using zeolite as the resin. The beds are alternatingly regenerated with sodium cloride. In addition, water used in steam generaters must typically be free of corrosive gases such as oxygen, Gabon dioxide, and hydrogen sulfide. Otherwise, the corrosive gases can cause corrosion to the hot, water wet, inner surface of the tubes in the steam generater. Various chemicals including sodium sulfite are typically used to scavenge the oxygen and thus limit corrosion.
Large quantities of feedwater are typically required for the operation of conventional thermal recovery or steam injection processes and equipment.
However, as discussed above, large quantities or sources of good quality feedwater are difficult to find. Surface water may be obtained from either lakes or rivers, however, this water may contain silt, bacteria, algae, dissolved minerals and gases.
Water from these sources tends to require filtering in order to remove any undissolved solids and to prevent fouling of the resin beds of the wafer softeners.
Fresh ground water produced from wells may not require filtering but tends to be higher in total dissolved minerals or solids (TDS). As well, the use of both surface water and fresh ground water from wells is restricted by government environmental agencies. Higher TDS water from deeper wells may be used but capital and operating costs to treat the water tend to increase with TDS
content and hardness. Water produced with crude oil (referred to as "produced water") tends to be even more difficult to treat since it usually contains oil fines and has a high mineral content. Thus, care must be taken first to remove any oil or hydrogen sulfide or it may foul the softener resins.
As a result of the need for relatively large quantities of feedwater for generation of steam for thermal recovery methods, and as a result of the need to soften and otherwise pretreat any feedwater typically used for such steam generation, obtaining or producing the necessary feedwater tends to be relatively costly. Thus, there remains a need in the oil and gas industry for an improved method and an improved apparatus for producing a relatively high temperature vapor for use in conventional thermal recovery methods for the production of hydrocarbons, and more particularly, for injection into a well. Further, there is a need for the method and apparatus to be relatively cost effective as compared with conventional steam generation processes and equipment.
Accordingly, there is a particular need for a method and an apparatus for producing an injection vapor which do not require the softening or pretreatment of any feedwater utilized in the method or apparatus. There is also a need for a method and an apparatus which can utilize produced water as at least a portion of the feedwater for the generation of an injection vapor to be injected into the well. Finally, there is a need for a method and an apparatus for producing an injection vapor from liquid hydrocarbons such as light hydrocarbon liquid which do not require the use of any feedwater in the method or apparatus. There is also a need for a combination of such methods and apparatus.
~LTMMARY OF INVENTION
The present invention relates to a method and an apparatus for producing a vapor for use in thermal recovery methods for the production of hydrocarbons. Further, the present invention relates to a method and an apparatus which are relatively cost effective as compared to conventional steam generation processes and equipment.
More particularly, the present invention relates to a method and an apparatus for producing an injection vapor for injection into a well. The injection vapor may be comprised of steam produced from water, or may be comprised of any other suitable gaseous substance or a combination or mixture thereof. Where the injection vapor is comprised substantially or partially of steam, the feedwater used in the process and the apparatus of the within invention to generate the steam does not require prior softening or pretreatment. As a result, the feedwater may be comprised of almost any type or quality of water, including pond water or produced water from a well. Where the injection vapor is not generated from water, it may be comprised of gaseous hydrocarbons generated from liquid hydrocarbons such as light hydrocarbon liquid produced from a well.
Where the method and the apparatus of the within invention utilize water to generate steam for injection, the water is preferably converted to about 100% quality steam. More preferably, the steam is slightly superheated in order to provide more heat to the well per unit of steam injected, thus reducing the amount of water that must be processed, injected into the well and subsequently produced with produced hydrocarbons.
In a method aspect of the invention, the invention is a method for producing, from a liquid, a vapor for injection into a well, comprising the steps of combining a quantity of the liquid with a quantity of an oil to produce a mixture of liquid and oil, heating the mixture of liquid and oil to produce from the liquid a quantity of the vapor, and then separating the vapor from the oil. The vapor produced by the method may then be injected into a well.
In an apparatus aspect of the invention, the invention is an apparatus for producing, from a liquid, a vapor for injection into a well, comprising a mixer for mixing a quantity of the liquid and a quantity of an oil to produce a mixture of liquid and oil, a heater for heating the mixture of liquid and oil to produce from the liquid a quatity of the vapor, and a first separator comprising an inlet, a vapor outlet and an oil outlet, for separating the vapor and the oil.
The oil that is used in the invention may be any kind of oil, but preferably at least a portion of the oil comprises crude oil obtained from a production fluid. The liquid that is used in the invention may be any kind of liquid, including light hydrocarbon liquid, produced water or pond water, which can be converted to a vapor at the temperatures and pressures of the method and apparatus and which is capable of transferring heat to a hydrocarbon bearing formation.
Preferably, at least a portion of the liquid comprises either produced water or light hydrocarbon liquid which are obtained from a production fluid. Combinations of different oils and liquids may also be used. For example, both produced water and light hydrocarbon liquid together may be used as the liquid to produce the vapor.
Accordingly, there is a particular need for a method and an apparatus for producing an injection vapor which do not require the softening or pretreatment of any feedwater utilized in the method or apparatus. There is also a need for a method and an apparatus which can utilize produced water as at least a portion of the feedwater for the generation of an injection vapor to be injected into the well. Finally, there is a need for a method and an apparatus for producing an injection vapor from liquid hydrocarbons such as light hydrocarbon liquid which do not require the use of any feedwater in the method or apparatus. There is also a need for a combination of such methods and apparatus.
~LTMMARY OF INVENTION
The present invention relates to a method and an apparatus for producing a vapor for use in thermal recovery methods for the production of hydrocarbons. Further, the present invention relates to a method and an apparatus which are relatively cost effective as compared to conventional steam generation processes and equipment.
More particularly, the present invention relates to a method and an apparatus for producing an injection vapor for injection into a well. The injection vapor may be comprised of steam produced from water, or may be comprised of any other suitable gaseous substance or a combination or mixture thereof. Where the injection vapor is comprised substantially or partially of steam, the feedwater used in the process and the apparatus of the within invention to generate the steam does not require prior softening or pretreatment. As a result, the feedwater may be comprised of almost any type or quality of water, including pond water or produced water from a well. Where the injection vapor is not generated from water, it may be comprised of gaseous hydrocarbons generated from liquid hydrocarbons such as light hydrocarbon liquid produced from a well.
Where the method and the apparatus of the within invention utilize water to generate steam for injection, the water is preferably converted to about 100% quality steam. More preferably, the steam is slightly superheated in order to provide more heat to the well per unit of steam injected, thus reducing the amount of water that must be processed, injected into the well and subsequently produced with produced hydrocarbons.
In a method aspect of the invention, the invention is a method for producing, from a liquid, a vapor for injection into a well, comprising the steps of combining a quantity of the liquid with a quantity of an oil to produce a mixture of liquid and oil, heating the mixture of liquid and oil to produce from the liquid a quantity of the vapor, and then separating the vapor from the oil. The vapor produced by the method may then be injected into a well.
In an apparatus aspect of the invention, the invention is an apparatus for producing, from a liquid, a vapor for injection into a well, comprising a mixer for mixing a quantity of the liquid and a quantity of an oil to produce a mixture of liquid and oil, a heater for heating the mixture of liquid and oil to produce from the liquid a quatity of the vapor, and a first separator comprising an inlet, a vapor outlet and an oil outlet, for separating the vapor and the oil.
The oil that is used in the invention may be any kind of oil, but preferably at least a portion of the oil comprises crude oil obtained from a production fluid. The liquid that is used in the invention may be any kind of liquid, including light hydrocarbon liquid, produced water or pond water, which can be converted to a vapor at the temperatures and pressures of the method and apparatus and which is capable of transferring heat to a hydrocarbon bearing formation.
Preferably, at least a portion of the liquid comprises either produced water or light hydrocarbon liquid which are obtained from a production fluid. Combinations of different oils and liquids may also be used. For example, both produced water and light hydrocarbon liquid together may be used as the liquid to produce the vapor.
Furthermore, produced water or light hydrocarbon liquid may be replaced with or supplemented by virtually any type or types of liquid.
Preferably, the oil and the liquid are obtained from production fluid from the same well that the vapor is injected into, or from a production well associated or in communication with the injection well, thus creating a self contained system for vapor injection which is not dependent upon external sources for oil or water. Oil recovered in the separating step may be recycled to be mixed with liquid. A water reservoir for containing produced water or water from some other source may also be provided as a water storage facility for water to be used in the method.
Where the oil and the liquid are obtained from production fluid, the invention may include the separation of the production fluid into various phases so that the different phases can be used in the invention. Where the liquid to be used comprises produced water, the production fluid may be separated into a produced water phase and a crude oil phase. Where the liquid to be used comprises light hydrocarbon liquid, the production fluid may be separated into a hydrocarbon vapor phase and a crude oil phase. Preferably, however, the production fluid is separated into a hydrocarbon vapor phase, a produced water phase and a crude oil phase, particularly where the liquid to be used comprises both light hydrocarbon liquid and produced water. The hydrocarbon vapor phase is then preferably condensed and the condensate is preferably separated from non-condensible vapors in order to minimize the buildup in the system of non-condensible vapors in the production fluid and in the hydrocarbon vapor phase.
Preferably, all of the produced crude oil from the well is used in the within invention. The crude oil serves as a carrying fluid to carry all dissolved and undissolved solids dropped from the evaporating water or vaporizing light hydrocarbon liquid. The crude oil may also serve as a corrosion and scaling inhibiter in the conduits of the apparatus. In addition, the light end vapours or lighter components of the crude oil and the condensed light ends that result from cooling in the apparatus may also act as inhibitors against corrosion in the piping of the apparatus and the injection well. When condensed downhole, Iight hydrocarbon liquid may also act as a diluent to further reduce the viscosity of the crude oil in the formation.
_5_ The liquid and the oil may be combined using any method or apparatus for mixing. Preferably, they are combined in a conduit under pressure and the pressure is maintained during heating of the mixture and separation of the vapor and the oil so that the vapor can be injected into the well without further pressurization. Preferably, the liquid and the oil are combined for mixing with the assistance of pumps.
The mixture may be heated in any manner. Preferably, the mixture is heated in a first heat exchanger which is preferably indirectly heated using heating oil. The mixture may also be preheated with a second heat exchanger which preferably is heated indirectly using the oil which is separated from the vapor in the separating step.
The vapor and the oil may be separated in any manner. Preferably, the vapor and the oil are separated in a separator which is a pressure vessel, so that the vapor is pressurized and ready for injection into the well after the separating step.
Preferably, any water contained in the mixture is converted to steam during the heating step of the invention so that for most applications of the invention the separation of the vapor and oil is a two phase separation.
Since the oil serves as a carrying fluid for dissolved and undissolved solids originally contained in the liquid, the-oil is preferably treated after it has been separated from the vapor to remove at least a portion of these solids. The oil may be treated to remove solids in any manner. Preferably, the oil is treated in an oil treater which may comprise an oil desalter. The treatment of the oil may involve mixing the oil with water so that the water absorbs dissolved and undissolved solids from the oil. The water may comprise produced water. The treatment of the oil may also comprise adding a demulsifier to the mixture of oil and water to control emulsification of the mixture. The treated oil may then be stored or transported for further processing while the water may be treated or disposed of.
Embodiments of the invention will now be described with reference to the accompanying drawings, in which:
Figure 1 is a schematic drawing of a preferred embodiment of the apparatus of the within invention, in which the vapor is comprised of steam generated from produced water from a production well;
Figure 2 is a schematic drawing of a first alternate embodiment of the apparatus of the within invention, in which the vapor is comprised of hydrocarbon vapor generated from light hydrocarbon liquid from a production well; and Figure 3 is a schematic drawing of a second alternate embodiment of the apparatus of the within invention, in which the vapor is comprised of a mixture or combination of steam generated from produced water and hydrocarbon vapor generated from light hydrocarbon liquid from a production well.
DETAILED DESCRIPTION
Referring to Figures 1-3, the invention relates to a method and apparatus for producing, from a liquid, a vapor (20) for injection into a well (22). In the preferred embodiment, the vapor (20) is produced at least in part using a production fluid from a producing well. Most preferably, the production fluid is obtained from the same well into which the vapor is ultimately injected or from a production well associated or communicating with the well into which the vapor is injected.
The liquid from which the vapor (20) is produced may comprise any substance in a liquid phase or condensed to a liquid phase which can readily be converted to vapor and which is capable of transferring an effective amount of heat to the well and thus the producing formation. In a typical production fluid, suitable liquids for use in producing the vapor in the within invention include produced wafer (26) and those hydrocarbons (24) which can be converted to vapor at the temperature and pressure conditions of the method and apparatus. Such hydrocarbons may be produced from a production well as either gases, liquids or condensates (such as gas condensates) and may be referred to as light hydrocarbons.
_7_ In this disclosure, light hydrocarbon liquid refers to light hydrocarbons which have either been produced as a liquid phase or have been condensed to a liquid phase.
Typical production wells produce hydrocarbons (24), produced water (26) and solids. The produced water (26), is typically mixed with or entrained in the hydrocarbons (24). The solids may include particles of clays, metals, silicates (such as sand and silt), salt and other solid matter. The hydrocarbons (24) comprise a wide range of compounds, some of which are gases when produced and some of which are liquids when produced. The gases are typically separated from the liquids and then either condensed for storage or transportation or burned or otherwise vented to the atmosphere. The liquids are typically stored or transported for further processing. In this disclosure, the gases are described as hydrocarbon vapors, the liquids are described as crude oil, and the term production fluid includes gaseous and liquid hydrocarbons (24) and produced water (26) collectively. These different components of production fluid are seldom if ever pure, and each component may contain amounts of one or more of the other components.
The vapor (20) is produced by the within invention for injection into a conventional injection well (22) in a manner, and utilizing conventional thermal recovery methods and apparatuses, such that the vapor (20) acts to facilitate the production of hydrocarbons (24) from the injection well or from a well associated or communicating with the injection well (22). Conventional thermal recovery methods for producing crude oil include cyclic steam injection, steam drive and steam assisted gravity drainage processes. The apparatus and process of the within invention may be used for the production of injection vapor for use with any thermal recovery methods.
In the preferred embodiment of the invention, as shown in Figure 1, the vapor (20) to be injected into the well (22) is generated substantially from the produced water (26) from the same well (22) or from a well associated or communicating with the well (22). However, alternatively, as shown in Figures and 3, the vapor (20) may be generated from light hydrocarbon liquid (28) from the well (22) or a well associated or communicating with the well (22), or from a mixture or combination of both produced water (20) and light hydrocarbon liquid (28). Furthermore, the vapor (20) may be generated from a production fluid from a different well or from one or more wells. The process and apparatus parameters for _B_ each of these embodiments are substantially similar except where specifically noted herein.
Referring to Figures 1- 3, the apparatus is comprised of a production fluid separator (30), which in the preferred embodiment is a free water knockout and degasser, for separating the production fluid from the well into a produced water phase comprising produced water (26), a hydrocarbon vapor phase comprising hydrocarbon vapor (32) and a crude oil phase comprising crude oil (34).
Specifically, the production fluid passes through a line (36) from the well (22) or from a well associated or communicating with the well (22) and enters the production fluid separator through an inlet (38).
Any form of three phase separator may be used as the production fluid separator (30) in practicing the invention. In the preferred embodiment, the inlet (38) is packed with Pall (trade-mark) rings to calm the flow in the vessel and provide a coalescing medium to separate the gas from the liquids. The liquids fall to the bottom of the production fluid separator (30) where the crude oil phase separates from and floats on top of the produced water phase. In the preferred embodiment, the production fluid separator (30) is heated to a temperature of about 250°
Fahrenheit and is pressurized to a pressure of about 100 pounds per square inch.
However, any suitable temperature and pressure compatible with both the production fluid separator (30) and the temperature and pressure of the production fluid obtained from the well (22) may be used.
The hydrocarbon vapor phase and any water vapor included in the heated production fluid exit the top of the production fluid separator (30) through a hydrocarbon vapor outlet (39) and pressure regulating valve (40) and are conveyed to a condenser (42) where condensible hydrocarbon vapor and water vapor are condensed into light hydrocarbon liquid (28). The light hydrocarbon liquid (28) and any uncondensible vapor pass through a line (44) into a condensate separator (46) through an inlet (48) which is also packed with Pall (trade-mark) rings. In the condensate separator (46), uncondensible vapor exits the top of the condensate separater (46) and is disposed of. A light hydrocarbon liquid pump (50) controlled by a liquid level controller pumps the light hydrocarbon liquid (28) either to a light hydrocarbon liquid reservoir (114) or directly to a mixer (52).
Produced water (26) which settles to the bottom of the production fluid separator (30) is released from a produced water outlet (53) by a valve (54) controlled by an interface controller (55) either to a water reservoir (56) or is pumped by a produced water pump (58) directly to the mixer (52). A cooler (not shown) may be provided between the produced water outlet (53) and the water reservoir (56) to cool the produced water (26) so that it does not flash or boil in the water reservoir (56).
Crude oil (34) is pumped from a crude oil outlet (60) in the production fluid separator (30) to the mixer (52) by a crude oil pump (62) controlled by a level controller (63).
The amount of produced water (26) pumped by the produced water pump (58) relative to the amount of crude oil (34) pumped by the crude oil pump (62) is determined by the desired vapor to oil ratio. The vapor to oil ratio is the optimum number of barrels of vapor that is required to be injected into the well (22) and thus the formation to result in the production from the well of one barrel of hydrocarbons (24). For most applications the vapor to oil ratio is approximately 3:1 but is dependent upon the characteristics of the formation and of the production fluid.
In the event that the amount of produced water (26) included in the production fluid of the well (22) is not sufficient to supply sufficient produced water (26) for use in the invention, then produced water (26) from other wells or water from other sources may be supplied to the water reservoir (56) as make-up water.
The present invention involves combining a quantity of a liquid and a quantity of an oil to produce a mixture of liquid and oil. In the embodiment of Figure 1, crude oil (34) as the oil and produced water (26) as the liquid are combined in the mixer (52). In the embodiment of Figure 2, crude oil (34) as the oil and light hydrocarbon liquid (28) as the liquid are combined in the mixer (52). In the embodiment of Figure 3, crude oil (34) as the oil and both produced water (26) and light hydrocarbon liquid (28) as the liquid are combined in the mixer (52). In all three preferred embodiments, the mixer (52) comprises a junction (64) at which point the oil and liquid are combined to produce the mixture. Other forms of mixer (52) may however be used. From the mixer, the mixture passes through a mixture conduit (66) which in turn passes first through a preheating heat exchanger (68) and then through a heat exchanger (70). The preheating heat exchanger (68) is optional.
One of the features of this invention is the preferred use of an indirect heating system to heat the mixture of crude oil (34) and produced water (26), crude oil (34) and light hydrocarbon liquid (28) or crude oil (34), produced water (26) and light hydrocarbon liquid (28), as the case may be, in order to convert the liquid to vapor (20). The indirect heating is preferably accomplished by using indirectly fired heat exchangers rather than direct fired heat exchangers or other direct fired heating apparatus. The use of indirect heated heat exchangers results in reduced temperature across the conduit conveying the mixture of crude oil (34) and liquid and may also reduce corrosion and scaling. By reducing scaling and eliminating the extreme high temperatures that result from direct firing, conduit rupture due to scale insulated hot spots is less likely to occur. Direct fired heat exchangers or other direct fired heating apparatus may, however, be used in the invention if care is taken.
'The preheating heat exchanger (68) and the heat exchanger (70) heat the mixture of oil and liquid in order to produce a quantity of vapor from the liquid.
The preheating heat exchanger partially heats the mixture by scavenging heat from crude oil (34) which is circulated through the preheating heat exchanger {68) from a vapor separator (72) located downstream. The heat exchanger (70) adds sufficient heat to turn substantially all of the liquid to vapor. The heat transferred to the mixture by the heat exchangers (68, 70) may also result in a portion of the light hydrocarbon liquid included in the crude oil (34) being turned to vapor.
The remaining crude oil (34) that is not vaporized serves to carry undissolved solids and dissolved solids that are left behind by the liquid and by the light constituents of the crude oil (34) as they are turned to vapor. The crude oil (34) may also act as a corrosion inhibiter and scale inhibiter in the heat exchangers (68, 70). In the preferred embodiment, the crude oil and vapor are heated to a temperature of approximately 600°F depending on the pressure required to inject the vapor into the well. The higher the injection pressure the higher the temperature must be in order to be above the saturation temperature of the vapor.
In the preferred embodiment, heat is supplied to the heat exchanger (70) by circulated heating oil. The heating oil is heated by a direct fired once through oil heater (74). The heating oil is preferably treated with corrosion inhibiters. In the oil heater (74), oxygen and other gases are removed and the closed. system is blanketed with inert gas to prevent any other gas entry into the system. The heating oil is circulated by a heating oil pump (76). The heating oil is heated to approximately 650°F by the oil heater (74). Heat may also be supplied to the heat exchanger (70) by other types of heaters and by circulating other types of heating fluids through the heat exchanger (70).
The heat exchangers (68, 70) are preferably multitube hairpin type heat exchangers. Multitube hairpin tubes consist of a single finned tube enclosed within another tube. The heating fluid flows in the inner tube which has fins on its external surface. The crude oil (34) and liquid to be heated flows in the annular space between the inner pipe and the outer pipe. There are a plurality of these pipes connected with hairpin turns to provide a long pipe system through which the heating oil and the mixture to be heated pass. These tubes have been used in oil treating to evaporate water off crude oil without significant problems with scaling, corrosion or fouling.
In the preferred embodiment, all or substantially all of the liquid is converted to vapor by passing the mixture through the heat exchangers (68, 70). In conventional steam injection systems, a portion of the liquid is maintained in its liquid phase in order to carry the dissolved and undissolved solids which are left behind when the liquid is vaporized, and this unvaporized liquid is typically injected into the well along with the vapor. As can be seen, this practice is relatively inefficient, since the full heat capacity of the liquid is not utilized. In the present invention, there is no need to maintain any of the liquid in its liquid phase since the crude oil (34) is intended to carry the dissolved and undissolved solids.
As a result, in the preferred embodiment when the mixture has passed through the heat exchangers (68, 70), the mixture consists almost exclusively of crude oil (34), minus its very light constituents which have been vaporized, and vapor (20).
From the heat exchangers (68, 70), the mixture passes through the mixture conduit (66) to an inlet (78) on the vapor separator (72). The vapor separator (72) is a two phase separator which functions to separate the vapor (20) from the crude oil (34). Under normal conditions, a three phase separator is not required for the vapor separator (72) since there should be a negligible amount of water remaining in the mixture.
The inlet (~8) of the vapor separator (72) is packed with l~'all (trade mark) rings to calm the flow and to provide a coalescing medium to separate the vapor from the crude oil. The vapor (20) exits the top of the vapor separator (72) through a vapor outlet (80) and is then injected into the well (22) through a vapor line (82). The crude oil (34) exits the bottom of the vapor separator (72) through a crude oil outlet (84).
It is desirable that the vapor (20) exit the vapor separator (72) at a pressure sufficient to enable it to be injected into the well (22) and the formation without first undergoing additional pr essurization. For most applications, a pressure of approximately 1500 pounds per square inch should be sufficient. In order to achieve this pressure, it is preferable that the mixture, and in particular the vapor (20) be contained in the conduit (66) to inhibit expansion of the vapor (20) in the conduit (66) and that the combining of the crude oil (34) and the liquid in the mixer (52) be performed at an elevated pressure. Furthermore, it is preferred that the vapor separator (72) be a pressure vessel so that the pressure of the vapor (20) at the vapor separator inlet (78) is substantially the same as the pressure of the vapor (20) at the vapor separator vapor outlet (80). In the preferred embodiment, the mixing step takes place at a pressure of about 1525 pounds per square inch with the assistance of pumps and this pressure is substantially maintained in the conduit (66) and in the vapor separator (72) so that the pressure of the vapor (20) at the vapor separator vapor outlet (80) is approximately 1500 pounds per square inch. At this pressure, the temperature required to create substantially 100% quality slightly superheated steam is about 600° Fahrenheit. If light hydrocarbon liquid (28) is included in the liquid, then a different temperature may be required to create substantially 100% quality slightly superheated hydrocarbon vapor at this pressure.
In the preferred embodiment, the crude oiI (34) then passes through a recirculating conduit (86) back through the preheating heat exchanger (68) where heat from the crude oil (34) is transferred to the mixture that is also passing through the preheating heat exchanger (68), thus cooling the crude oil (34). From the preheating heat exchanger (68), the crude oil (34) passes through the recirculating conduit (86) to an oil treater (88). A level controller (90) in the vapor separator (72) controls a dump valve (92) in the recirculating conduit (86) to control the flow of crude oil (34) to the oil treater (88).
Referring to Figure 2, it can be seen that where the liquid to be vaporized in the within invention consists substantially of hydrocarbon liquid such as light hydrocarbon liquid (28), the oil treater (88) may not be required.
The reason for this is that hydrocarbon liquid is unlikely to carry with it a significant amount of dissolved or undissolved solids, with the result that the solids content of the crude oil (34) is not increased significantly, which in turn means that the crude oil (34) will be in substantially the same condition it was in when originally produced from the well (22). The need for the oil treater (88) in the within invention will therefore depend upon the characteristics of the liquid to be vaporized.
In the preferred embodiment, the oil treater (88) comprises conventional desalting apparatus and conventional desalting methods are used to remove the dissolved and undissolved solids from the crude oil (34) after the vaporization of the liquid has taken place in the presence of the crude oil (34). Other apparatus and methods may however be used.
In the preferred embodiment, the oil treater (88) comprises an oil desalter (94). The oil desalter (94) serves to remove dissolved and undissolved solids from the crude oil (34). This is achieved by standard desalting methods used in the industry. One method, as shown in Figure 1, involves the mixing in a mixer (96) of relatively fresh water, such as produced water (26) supplied by a desalting water pump (98), into the crude oil (34) to absorb dissolved and undissolved solids from the crude oil (34). The addii:ion of demulsifier (100) controls the emulsification that occurs during the mixing process. The finer the emulsion created the better the contact between the crude oil (34) and water and the better the transfer of dissolved and undissolved solids from the crude oil (34) to the water.
However, the finer the emulsion the more difficult it can be to separate the crude oil (34) and water after this transfer of solids has taken place.
Separation of the "clean" crude oil (34) and "salty" water occurs by gravity in the oil desalter (94). The clean crude oil (34) is passed through an oil cooler (101) and then released to a sales oil tank (102) through a dump valve (104) controlled by a level controller (106) in the oil desalter (94). The "salty"
water is released to a salt water tank (108) through a dump valve (110) controlled by an interface level controller (112) in the oil desalter (94). Hydrocarbon vapor or water vapor which separates from the crude oil (34) is released from the oil desalter (94) through a desalter gas regulating valve (113).
Separation of the crude oil (34) and water, or desalting, is typically carried out at temperatures in the range of 212°F to 300°F. The amount of produced water (26) which is mixed with the crude oil (34) in the mixer (96) depends in part upon the salinity of the produced water (26) and the amont of dissolved and undissolved solids contained in the crude oil (34). In conventiona.I desalting procedures, the amount of produced water that is added is typically in the range of about 10% by volume of the crude oil (34). In the desalting procedures relating to the present invention, the amount of produced water (26) which must be added to the crude oil (34) may be as high as approximately 30% by volume of oil, due to the relatively high amount of dissolved and undissolved solids which are likely to be contained in the crude oil (34) as a result of performing the method of the within invention. From the salt water tank (108), the "salty" water that is separated from the crude oil (34) in the oil desalter (94) may be disposed of in deep salt water wells, may be treated, or may be transported from the well site for disposal or treatment.
From the sales oil tank (102), the "clean" crude oil (34) may be transported for processing. Optionally, all or a portion of the clean crude oil (34) may be recycled to the mixer (52).
Referring to Figure 2, in circumstances where the oil treater (88) is not required, the crude oil recirculating conduit (86) may pass from the preheating heat exchanger (68) to the oil cooler (101) where the crude oil (34) is further cooled, and may then pass directly to the sales oil tank (102) controlled by the dump valve (92) and the level controller (90).
Referring to Figures 2 and 3, a light hydrocarbon liquid reservoir (114) may be provided for storing light hydrocarbon liquid (28) which exits the condensate separator (46). The light hydrocarbon liquid pump (50) may then be used either to supply the light hydrocarbon liquid reservoir (114) or to supply the mixer (52). Light hydrocarbon liquid (28) may also be supplied to the mixer (52) from the light hydrocarbon liquid reservoir (114) using a light hydrocarbon liquid reservoir pump (116).
If the amount of light hydrocarbon liquid (28) separated from the production fluid on an ongoing basis is insufficient for use in the method, then light hydrocarbon liquid (28) may be supplied to the mixer from both the condensate separator (46) and the light hydrocarbon liquid reservoir (114). Light hydrocarbon liquid (28) may in turn be supplied to the light hydrocarbon liquid reservoir (114) either from production fluid or from some other source or sources.
Preferably, the oil and the liquid are obtained from production fluid from the same well that the vapor is injected into, or from a production well associated or in communication with the injection well, thus creating a self contained system for vapor injection which is not dependent upon external sources for oil or water. Oil recovered in the separating step may be recycled to be mixed with liquid. A water reservoir for containing produced water or water from some other source may also be provided as a water storage facility for water to be used in the method.
Where the oil and the liquid are obtained from production fluid, the invention may include the separation of the production fluid into various phases so that the different phases can be used in the invention. Where the liquid to be used comprises produced water, the production fluid may be separated into a produced water phase and a crude oil phase. Where the liquid to be used comprises light hydrocarbon liquid, the production fluid may be separated into a hydrocarbon vapor phase and a crude oil phase. Preferably, however, the production fluid is separated into a hydrocarbon vapor phase, a produced water phase and a crude oil phase, particularly where the liquid to be used comprises both light hydrocarbon liquid and produced water. The hydrocarbon vapor phase is then preferably condensed and the condensate is preferably separated from non-condensible vapors in order to minimize the buildup in the system of non-condensible vapors in the production fluid and in the hydrocarbon vapor phase.
Preferably, all of the produced crude oil from the well is used in the within invention. The crude oil serves as a carrying fluid to carry all dissolved and undissolved solids dropped from the evaporating water or vaporizing light hydrocarbon liquid. The crude oil may also serve as a corrosion and scaling inhibiter in the conduits of the apparatus. In addition, the light end vapours or lighter components of the crude oil and the condensed light ends that result from cooling in the apparatus may also act as inhibitors against corrosion in the piping of the apparatus and the injection well. When condensed downhole, Iight hydrocarbon liquid may also act as a diluent to further reduce the viscosity of the crude oil in the formation.
_5_ The liquid and the oil may be combined using any method or apparatus for mixing. Preferably, they are combined in a conduit under pressure and the pressure is maintained during heating of the mixture and separation of the vapor and the oil so that the vapor can be injected into the well without further pressurization. Preferably, the liquid and the oil are combined for mixing with the assistance of pumps.
The mixture may be heated in any manner. Preferably, the mixture is heated in a first heat exchanger which is preferably indirectly heated using heating oil. The mixture may also be preheated with a second heat exchanger which preferably is heated indirectly using the oil which is separated from the vapor in the separating step.
The vapor and the oil may be separated in any manner. Preferably, the vapor and the oil are separated in a separator which is a pressure vessel, so that the vapor is pressurized and ready for injection into the well after the separating step.
Preferably, any water contained in the mixture is converted to steam during the heating step of the invention so that for most applications of the invention the separation of the vapor and oil is a two phase separation.
Since the oil serves as a carrying fluid for dissolved and undissolved solids originally contained in the liquid, the-oil is preferably treated after it has been separated from the vapor to remove at least a portion of these solids. The oil may be treated to remove solids in any manner. Preferably, the oil is treated in an oil treater which may comprise an oil desalter. The treatment of the oil may involve mixing the oil with water so that the water absorbs dissolved and undissolved solids from the oil. The water may comprise produced water. The treatment of the oil may also comprise adding a demulsifier to the mixture of oil and water to control emulsification of the mixture. The treated oil may then be stored or transported for further processing while the water may be treated or disposed of.
Embodiments of the invention will now be described with reference to the accompanying drawings, in which:
Figure 1 is a schematic drawing of a preferred embodiment of the apparatus of the within invention, in which the vapor is comprised of steam generated from produced water from a production well;
Figure 2 is a schematic drawing of a first alternate embodiment of the apparatus of the within invention, in which the vapor is comprised of hydrocarbon vapor generated from light hydrocarbon liquid from a production well; and Figure 3 is a schematic drawing of a second alternate embodiment of the apparatus of the within invention, in which the vapor is comprised of a mixture or combination of steam generated from produced water and hydrocarbon vapor generated from light hydrocarbon liquid from a production well.
DETAILED DESCRIPTION
Referring to Figures 1-3, the invention relates to a method and apparatus for producing, from a liquid, a vapor (20) for injection into a well (22). In the preferred embodiment, the vapor (20) is produced at least in part using a production fluid from a producing well. Most preferably, the production fluid is obtained from the same well into which the vapor is ultimately injected or from a production well associated or communicating with the well into which the vapor is injected.
The liquid from which the vapor (20) is produced may comprise any substance in a liquid phase or condensed to a liquid phase which can readily be converted to vapor and which is capable of transferring an effective amount of heat to the well and thus the producing formation. In a typical production fluid, suitable liquids for use in producing the vapor in the within invention include produced wafer (26) and those hydrocarbons (24) which can be converted to vapor at the temperature and pressure conditions of the method and apparatus. Such hydrocarbons may be produced from a production well as either gases, liquids or condensates (such as gas condensates) and may be referred to as light hydrocarbons.
_7_ In this disclosure, light hydrocarbon liquid refers to light hydrocarbons which have either been produced as a liquid phase or have been condensed to a liquid phase.
Typical production wells produce hydrocarbons (24), produced water (26) and solids. The produced water (26), is typically mixed with or entrained in the hydrocarbons (24). The solids may include particles of clays, metals, silicates (such as sand and silt), salt and other solid matter. The hydrocarbons (24) comprise a wide range of compounds, some of which are gases when produced and some of which are liquids when produced. The gases are typically separated from the liquids and then either condensed for storage or transportation or burned or otherwise vented to the atmosphere. The liquids are typically stored or transported for further processing. In this disclosure, the gases are described as hydrocarbon vapors, the liquids are described as crude oil, and the term production fluid includes gaseous and liquid hydrocarbons (24) and produced water (26) collectively. These different components of production fluid are seldom if ever pure, and each component may contain amounts of one or more of the other components.
The vapor (20) is produced by the within invention for injection into a conventional injection well (22) in a manner, and utilizing conventional thermal recovery methods and apparatuses, such that the vapor (20) acts to facilitate the production of hydrocarbons (24) from the injection well or from a well associated or communicating with the injection well (22). Conventional thermal recovery methods for producing crude oil include cyclic steam injection, steam drive and steam assisted gravity drainage processes. The apparatus and process of the within invention may be used for the production of injection vapor for use with any thermal recovery methods.
In the preferred embodiment of the invention, as shown in Figure 1, the vapor (20) to be injected into the well (22) is generated substantially from the produced water (26) from the same well (22) or from a well associated or communicating with the well (22). However, alternatively, as shown in Figures and 3, the vapor (20) may be generated from light hydrocarbon liquid (28) from the well (22) or a well associated or communicating with the well (22), or from a mixture or combination of both produced water (20) and light hydrocarbon liquid (28). Furthermore, the vapor (20) may be generated from a production fluid from a different well or from one or more wells. The process and apparatus parameters for _B_ each of these embodiments are substantially similar except where specifically noted herein.
Referring to Figures 1- 3, the apparatus is comprised of a production fluid separator (30), which in the preferred embodiment is a free water knockout and degasser, for separating the production fluid from the well into a produced water phase comprising produced water (26), a hydrocarbon vapor phase comprising hydrocarbon vapor (32) and a crude oil phase comprising crude oil (34).
Specifically, the production fluid passes through a line (36) from the well (22) or from a well associated or communicating with the well (22) and enters the production fluid separator through an inlet (38).
Any form of three phase separator may be used as the production fluid separator (30) in practicing the invention. In the preferred embodiment, the inlet (38) is packed with Pall (trade-mark) rings to calm the flow in the vessel and provide a coalescing medium to separate the gas from the liquids. The liquids fall to the bottom of the production fluid separator (30) where the crude oil phase separates from and floats on top of the produced water phase. In the preferred embodiment, the production fluid separator (30) is heated to a temperature of about 250°
Fahrenheit and is pressurized to a pressure of about 100 pounds per square inch.
However, any suitable temperature and pressure compatible with both the production fluid separator (30) and the temperature and pressure of the production fluid obtained from the well (22) may be used.
The hydrocarbon vapor phase and any water vapor included in the heated production fluid exit the top of the production fluid separator (30) through a hydrocarbon vapor outlet (39) and pressure regulating valve (40) and are conveyed to a condenser (42) where condensible hydrocarbon vapor and water vapor are condensed into light hydrocarbon liquid (28). The light hydrocarbon liquid (28) and any uncondensible vapor pass through a line (44) into a condensate separator (46) through an inlet (48) which is also packed with Pall (trade-mark) rings. In the condensate separator (46), uncondensible vapor exits the top of the condensate separater (46) and is disposed of. A light hydrocarbon liquid pump (50) controlled by a liquid level controller pumps the light hydrocarbon liquid (28) either to a light hydrocarbon liquid reservoir (114) or directly to a mixer (52).
Produced water (26) which settles to the bottom of the production fluid separator (30) is released from a produced water outlet (53) by a valve (54) controlled by an interface controller (55) either to a water reservoir (56) or is pumped by a produced water pump (58) directly to the mixer (52). A cooler (not shown) may be provided between the produced water outlet (53) and the water reservoir (56) to cool the produced water (26) so that it does not flash or boil in the water reservoir (56).
Crude oil (34) is pumped from a crude oil outlet (60) in the production fluid separator (30) to the mixer (52) by a crude oil pump (62) controlled by a level controller (63).
The amount of produced water (26) pumped by the produced water pump (58) relative to the amount of crude oil (34) pumped by the crude oil pump (62) is determined by the desired vapor to oil ratio. The vapor to oil ratio is the optimum number of barrels of vapor that is required to be injected into the well (22) and thus the formation to result in the production from the well of one barrel of hydrocarbons (24). For most applications the vapor to oil ratio is approximately 3:1 but is dependent upon the characteristics of the formation and of the production fluid.
In the event that the amount of produced water (26) included in the production fluid of the well (22) is not sufficient to supply sufficient produced water (26) for use in the invention, then produced water (26) from other wells or water from other sources may be supplied to the water reservoir (56) as make-up water.
The present invention involves combining a quantity of a liquid and a quantity of an oil to produce a mixture of liquid and oil. In the embodiment of Figure 1, crude oil (34) as the oil and produced water (26) as the liquid are combined in the mixer (52). In the embodiment of Figure 2, crude oil (34) as the oil and light hydrocarbon liquid (28) as the liquid are combined in the mixer (52). In the embodiment of Figure 3, crude oil (34) as the oil and both produced water (26) and light hydrocarbon liquid (28) as the liquid are combined in the mixer (52). In all three preferred embodiments, the mixer (52) comprises a junction (64) at which point the oil and liquid are combined to produce the mixture. Other forms of mixer (52) may however be used. From the mixer, the mixture passes through a mixture conduit (66) which in turn passes first through a preheating heat exchanger (68) and then through a heat exchanger (70). The preheating heat exchanger (68) is optional.
One of the features of this invention is the preferred use of an indirect heating system to heat the mixture of crude oil (34) and produced water (26), crude oil (34) and light hydrocarbon liquid (28) or crude oil (34), produced water (26) and light hydrocarbon liquid (28), as the case may be, in order to convert the liquid to vapor (20). The indirect heating is preferably accomplished by using indirectly fired heat exchangers rather than direct fired heat exchangers or other direct fired heating apparatus. The use of indirect heated heat exchangers results in reduced temperature across the conduit conveying the mixture of crude oil (34) and liquid and may also reduce corrosion and scaling. By reducing scaling and eliminating the extreme high temperatures that result from direct firing, conduit rupture due to scale insulated hot spots is less likely to occur. Direct fired heat exchangers or other direct fired heating apparatus may, however, be used in the invention if care is taken.
'The preheating heat exchanger (68) and the heat exchanger (70) heat the mixture of oil and liquid in order to produce a quantity of vapor from the liquid.
The preheating heat exchanger partially heats the mixture by scavenging heat from crude oil (34) which is circulated through the preheating heat exchanger {68) from a vapor separator (72) located downstream. The heat exchanger (70) adds sufficient heat to turn substantially all of the liquid to vapor. The heat transferred to the mixture by the heat exchangers (68, 70) may also result in a portion of the light hydrocarbon liquid included in the crude oil (34) being turned to vapor.
The remaining crude oil (34) that is not vaporized serves to carry undissolved solids and dissolved solids that are left behind by the liquid and by the light constituents of the crude oil (34) as they are turned to vapor. The crude oil (34) may also act as a corrosion inhibiter and scale inhibiter in the heat exchangers (68, 70). In the preferred embodiment, the crude oil and vapor are heated to a temperature of approximately 600°F depending on the pressure required to inject the vapor into the well. The higher the injection pressure the higher the temperature must be in order to be above the saturation temperature of the vapor.
In the preferred embodiment, heat is supplied to the heat exchanger (70) by circulated heating oil. The heating oil is heated by a direct fired once through oil heater (74). The heating oil is preferably treated with corrosion inhibiters. In the oil heater (74), oxygen and other gases are removed and the closed. system is blanketed with inert gas to prevent any other gas entry into the system. The heating oil is circulated by a heating oil pump (76). The heating oil is heated to approximately 650°F by the oil heater (74). Heat may also be supplied to the heat exchanger (70) by other types of heaters and by circulating other types of heating fluids through the heat exchanger (70).
The heat exchangers (68, 70) are preferably multitube hairpin type heat exchangers. Multitube hairpin tubes consist of a single finned tube enclosed within another tube. The heating fluid flows in the inner tube which has fins on its external surface. The crude oil (34) and liquid to be heated flows in the annular space between the inner pipe and the outer pipe. There are a plurality of these pipes connected with hairpin turns to provide a long pipe system through which the heating oil and the mixture to be heated pass. These tubes have been used in oil treating to evaporate water off crude oil without significant problems with scaling, corrosion or fouling.
In the preferred embodiment, all or substantially all of the liquid is converted to vapor by passing the mixture through the heat exchangers (68, 70). In conventional steam injection systems, a portion of the liquid is maintained in its liquid phase in order to carry the dissolved and undissolved solids which are left behind when the liquid is vaporized, and this unvaporized liquid is typically injected into the well along with the vapor. As can be seen, this practice is relatively inefficient, since the full heat capacity of the liquid is not utilized. In the present invention, there is no need to maintain any of the liquid in its liquid phase since the crude oil (34) is intended to carry the dissolved and undissolved solids.
As a result, in the preferred embodiment when the mixture has passed through the heat exchangers (68, 70), the mixture consists almost exclusively of crude oil (34), minus its very light constituents which have been vaporized, and vapor (20).
From the heat exchangers (68, 70), the mixture passes through the mixture conduit (66) to an inlet (78) on the vapor separator (72). The vapor separator (72) is a two phase separator which functions to separate the vapor (20) from the crude oil (34). Under normal conditions, a three phase separator is not required for the vapor separator (72) since there should be a negligible amount of water remaining in the mixture.
The inlet (~8) of the vapor separator (72) is packed with l~'all (trade mark) rings to calm the flow and to provide a coalescing medium to separate the vapor from the crude oil. The vapor (20) exits the top of the vapor separator (72) through a vapor outlet (80) and is then injected into the well (22) through a vapor line (82). The crude oil (34) exits the bottom of the vapor separator (72) through a crude oil outlet (84).
It is desirable that the vapor (20) exit the vapor separator (72) at a pressure sufficient to enable it to be injected into the well (22) and the formation without first undergoing additional pr essurization. For most applications, a pressure of approximately 1500 pounds per square inch should be sufficient. In order to achieve this pressure, it is preferable that the mixture, and in particular the vapor (20) be contained in the conduit (66) to inhibit expansion of the vapor (20) in the conduit (66) and that the combining of the crude oil (34) and the liquid in the mixer (52) be performed at an elevated pressure. Furthermore, it is preferred that the vapor separator (72) be a pressure vessel so that the pressure of the vapor (20) at the vapor separator inlet (78) is substantially the same as the pressure of the vapor (20) at the vapor separator vapor outlet (80). In the preferred embodiment, the mixing step takes place at a pressure of about 1525 pounds per square inch with the assistance of pumps and this pressure is substantially maintained in the conduit (66) and in the vapor separator (72) so that the pressure of the vapor (20) at the vapor separator vapor outlet (80) is approximately 1500 pounds per square inch. At this pressure, the temperature required to create substantially 100% quality slightly superheated steam is about 600° Fahrenheit. If light hydrocarbon liquid (28) is included in the liquid, then a different temperature may be required to create substantially 100% quality slightly superheated hydrocarbon vapor at this pressure.
In the preferred embodiment, the crude oiI (34) then passes through a recirculating conduit (86) back through the preheating heat exchanger (68) where heat from the crude oil (34) is transferred to the mixture that is also passing through the preheating heat exchanger (68), thus cooling the crude oil (34). From the preheating heat exchanger (68), the crude oil (34) passes through the recirculating conduit (86) to an oil treater (88). A level controller (90) in the vapor separator (72) controls a dump valve (92) in the recirculating conduit (86) to control the flow of crude oil (34) to the oil treater (88).
Referring to Figure 2, it can be seen that where the liquid to be vaporized in the within invention consists substantially of hydrocarbon liquid such as light hydrocarbon liquid (28), the oil treater (88) may not be required.
The reason for this is that hydrocarbon liquid is unlikely to carry with it a significant amount of dissolved or undissolved solids, with the result that the solids content of the crude oil (34) is not increased significantly, which in turn means that the crude oil (34) will be in substantially the same condition it was in when originally produced from the well (22). The need for the oil treater (88) in the within invention will therefore depend upon the characteristics of the liquid to be vaporized.
In the preferred embodiment, the oil treater (88) comprises conventional desalting apparatus and conventional desalting methods are used to remove the dissolved and undissolved solids from the crude oil (34) after the vaporization of the liquid has taken place in the presence of the crude oil (34). Other apparatus and methods may however be used.
In the preferred embodiment, the oil treater (88) comprises an oil desalter (94). The oil desalter (94) serves to remove dissolved and undissolved solids from the crude oil (34). This is achieved by standard desalting methods used in the industry. One method, as shown in Figure 1, involves the mixing in a mixer (96) of relatively fresh water, such as produced water (26) supplied by a desalting water pump (98), into the crude oil (34) to absorb dissolved and undissolved solids from the crude oil (34). The addii:ion of demulsifier (100) controls the emulsification that occurs during the mixing process. The finer the emulsion created the better the contact between the crude oil (34) and water and the better the transfer of dissolved and undissolved solids from the crude oil (34) to the water.
However, the finer the emulsion the more difficult it can be to separate the crude oil (34) and water after this transfer of solids has taken place.
Separation of the "clean" crude oil (34) and "salty" water occurs by gravity in the oil desalter (94). The clean crude oil (34) is passed through an oil cooler (101) and then released to a sales oil tank (102) through a dump valve (104) controlled by a level controller (106) in the oil desalter (94). The "salty"
water is released to a salt water tank (108) through a dump valve (110) controlled by an interface level controller (112) in the oil desalter (94). Hydrocarbon vapor or water vapor which separates from the crude oil (34) is released from the oil desalter (94) through a desalter gas regulating valve (113).
Separation of the crude oil (34) and water, or desalting, is typically carried out at temperatures in the range of 212°F to 300°F. The amount of produced water (26) which is mixed with the crude oil (34) in the mixer (96) depends in part upon the salinity of the produced water (26) and the amont of dissolved and undissolved solids contained in the crude oil (34). In conventiona.I desalting procedures, the amount of produced water that is added is typically in the range of about 10% by volume of the crude oil (34). In the desalting procedures relating to the present invention, the amount of produced water (26) which must be added to the crude oil (34) may be as high as approximately 30% by volume of oil, due to the relatively high amount of dissolved and undissolved solids which are likely to be contained in the crude oil (34) as a result of performing the method of the within invention. From the salt water tank (108), the "salty" water that is separated from the crude oil (34) in the oil desalter (94) may be disposed of in deep salt water wells, may be treated, or may be transported from the well site for disposal or treatment.
From the sales oil tank (102), the "clean" crude oil (34) may be transported for processing. Optionally, all or a portion of the clean crude oil (34) may be recycled to the mixer (52).
Referring to Figure 2, in circumstances where the oil treater (88) is not required, the crude oil recirculating conduit (86) may pass from the preheating heat exchanger (68) to the oil cooler (101) where the crude oil (34) is further cooled, and may then pass directly to the sales oil tank (102) controlled by the dump valve (92) and the level controller (90).
Referring to Figures 2 and 3, a light hydrocarbon liquid reservoir (114) may be provided for storing light hydrocarbon liquid (28) which exits the condensate separator (46). The light hydrocarbon liquid pump (50) may then be used either to supply the light hydrocarbon liquid reservoir (114) or to supply the mixer (52). Light hydrocarbon liquid (28) may also be supplied to the mixer (52) from the light hydrocarbon liquid reservoir (114) using a light hydrocarbon liquid reservoir pump (116).
If the amount of light hydrocarbon liquid (28) separated from the production fluid on an ongoing basis is insufficient for use in the method, then light hydrocarbon liquid (28) may be supplied to the mixer from both the condensate separator (46) and the light hydrocarbon liquid reservoir (114). Light hydrocarbon liquid (28) may in turn be supplied to the light hydrocarbon liquid reservoir (114) either from production fluid or from some other source or sources.
Claims (32)
1. A method for producing, from a liquid, a vapor for injection into a well, comprising the following steps in the sequence set forth:
(a) combining a quantity of the liquid with a quantity of an oil to produce a mixture of liquid and oil;
(b) heating the mixture of liquid and oil to produce from the liquid a quantity of the vapor; and (c) separating the vapor and the oil.
(a) combining a quantity of the liquid with a quantity of an oil to produce a mixture of liquid and oil;
(b) heating the mixture of liquid and oil to produce from the liquid a quantity of the vapor; and (c) separating the vapor and the oil.
2. The method as claimed in claim 1 wherein the oil is comprised of crude oil.
3. The method as claimed in claim 2 wherein the liquid is comprised of produced water which has been separated from crude oil.
4. The method as claimed in claim 2 wherein the liquid is comprised of a hydrocarbon liquid.
5. The method as claimed in claim 4 wherein the hydrocarbon liquid is comprised of a light hydrocarbon liquid which has been separated from crude oil.
6. The method as claimed in claim 2 wherein the liquid is comprised of water and a hydrocarbon liquid.
7. The method as claimed in claim 6 wherein the water is comprised of produced water which has been separated from crude oil and wherein the hydrocarbon liquid is comprised of a light hydrocarbon liquid which has been separated from crude oil.
8. The method as claimed in claim 3 wherein the quantity of vapor is produced from substantially all of the quantity of liquid.
9. The method as claimed in claim 8 wherein the vapor is substantially 100% quality.
10. The method as claimed in claim 9 wherein the vapor is superheated.
11. The method as claimed in claim 8 wherein the heating step is performed in a heat exchanger.
12. The method as claimed in claim 11 further comprising the step, after the step of separating the vapor and the oil, of circulating at least a portion of the quantity of the oil through a preheating heat exchanger, and wherein the heating step comprises preheating the mixture of liquid and oil by passing it through the preheating heat exchanger to be preheated by the circulating oil and subsequently heating the mixture of liquid and oil by passing it through the heat exchanger.
13. The method as claimed in claim 12 further comprising the step, after the step of separating the vapor and the oil, of treating the quantity of the oil to remove solids from the oil.
14. The method as claimed in claim 3 wherein the quantify of produced water and the quantity of oil are obtained by the step, before the combining step, of separating a production fluid into a produced water phase and a crude oil phase.
15. The method as claimed in claim 5 wherein the quantity of hydrocarbon liquid and the quantity of oil are obtained by the steps, before the combining step, of separating a production fluid into a hydrocarbon vapor phase and a crude oil phase and then condensing the hydrocarbon vapor phase to produce light hydrocarbon liquid.
16. The method as claimed in claim 7 wherein the quantity of liquid and the quantity of oil are obtained by the steps, before the combining step, of separating a production fluid into a hydrocarbon vapor phase, a produced water phase and a crude oil phase and then condensing the hydrocarbon vapor phase to produce light hydrocarbon liquid.
17. The method as claimed in claim 3, 5 or 7 further comprising the step of containing the vapor during the heating and separating steps in order to produce a pressurized vapor for injection into the well.
18. The method as claimed in claim 17 further comprising the step of pressurizing the mixture during the combining step.
19. An apparatus for producing, from a liquid, a vapor for injection into a well, comprising:
(a) a mixer for mixing a quantity of the liquid and a quantity of an oil to produce a mixture of liquid and oil;
(b) a heater for heating the mixture of liquid and oil to produce from the liquid a quantity of the vapor;
(c) a vapor separator comprising an inlet, a vapor outlet and an oil outlet, for separating the vapor and the oil.
(a) a mixer for mixing a quantity of the liquid and a quantity of an oil to produce a mixture of liquid and oil;
(b) a heater for heating the mixture of liquid and oil to produce from the liquid a quantity of the vapor;
(c) a vapor separator comprising an inlet, a vapor outlet and an oil outlet, for separating the vapor and the oil.
20. The apparatus as claimed in claim 19 wherein the vapor separator comprises a pressure vessel for containing the vapor during separation of the vapor and the oil to produce a pressurized vapor for injection into the well.
21. The apparatus as claimed in claim 20 wherein the heater comprises a heat exchanger.
22. The apparatus as claimed in claim 21, further comprising a mixture conduit extending between the mixer and the vapor separator for containing the mixture, which mixture conduit passes through the heat exchanger to facilitate heating of the mixture.
23. The apparatus as claimed in claim 22, further comprising a production fluid separator for separating a production fluid into a hydrocarbon vapor phase, a produced water phase and a crude oil phase, wherein the production fluid separator comprises a hydrocarbon vapor outlet, a produced water outlet and a crude oil outlet, and wherein the crude oil outlet and at least one of the hydrocarbon vapor outlet and the produced water outlet communicate with the mixer in order to supply the mixer with liquid and crude oil for mixing.
24. The apparatus as claimed in claim 23, further comprising a crude oil pump for pumping crude oil from the production fluid separator to the mixer.
25. The apparatus as claimed in claim 24, further comprising a produced water pump for pumping produced water from the production fluid separator to the mixer.
26. The apparatus as claimed in claim 25, further comprising a water reservoir which communicates with the produced water pump, for providing storage of water which is supplied by the production fluid separator.
27. The apparatus as claimed in claim 24, further comprising a hydrocarbon vapor condenser which communicates with the hydrocarbon vapor outlet of the production fluid separator, for condensing the hydrocarbon vapor into light hydrocarbon liquid.
28. The apparatus as claimed in claim 27, further comprising a condensate separator associated with the hydrocarbon vapor condenser, for separating light hydrocarbon liquid from non-condensible hydrocarbon vapor.
29. The apparatus as claimed in claim 28, further comprising a light hydrocarbon liquid pump for pumping light hydrocarbon liquid from the condensate separator to the mixer.
30. The apparatus as claimed in claim 29, further comprising a light hydrocarbon liquid reservoir which communicates with the light hydrocarbon liquid pump, for providing storage of light hydrocarbon liquid which is supplied by the condensate separator.
31. The apparatus as claimed in claim 22, further comprising a recirculating conduit extending from the oil outlet of the vapor separator, wherein the heater comprises a preheating heat exchanger for preheating the mixture, and wherein the recirculating conduit and the mixture conduit both pass through the preheating heat exchanger so that the mixture can be preheated by oil from the vapor separator as it passes through the preheating heat exchanger.
32. The apparatus as claimed in claim 31, further comprising an oil treater for treating the oil from the vapor separator, wherein the oil treater communicates with the oil outlet of the vapor separator through the recirculating conduit.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2233057 CA2233057A1 (en) | 1998-03-24 | 1998-03-24 | Produced water and light hydrocarbon liquid vapor injection method and apparatus |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2233057 CA2233057A1 (en) | 1998-03-24 | 1998-03-24 | Produced water and light hydrocarbon liquid vapor injection method and apparatus |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2233057A1 true CA2233057A1 (en) | 1999-09-24 |
Family
ID=29409506
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2233057 Abandoned CA2233057A1 (en) | 1998-03-24 | 1998-03-24 | Produced water and light hydrocarbon liquid vapor injection method and apparatus |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2233057A1 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN107882547A (en) * | 2016-09-29 | 2018-04-06 | 中国石油化工股份有限公司 | Duct type high-water-cut oil-producing well produces liquid three-phase metering mechanism and method |
-
1998
- 1998-03-24 CA CA 2233057 patent/CA2233057A1/en not_active Abandoned
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN107882547A (en) * | 2016-09-29 | 2018-04-06 | 中国石油化工股份有限公司 | Duct type high-water-cut oil-producing well produces liquid three-phase metering mechanism and method |
| CN107882547B (en) * | 2016-09-29 | 2023-08-04 | 中国石油化工股份有限公司 | Pipeline type high-water-content oil well liquid production three-phase metering device and method |
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