PROCESS FOR PRODUCING OIL

Abstract

Heavy oil or bitumen is recovered by injecting an oil recovery formulation comprising ammonia and steam having a vapor quality of from greater than 0 to less than 0.7, or injecting components thereof, into an underground oil-bearing formation comprising oil or bitumen having a total acid number of at least 0.1 and producing oil or bitumen from the formation after injection of the oil recovery formulation, or components thereof, into the formation.

Description

This application claims priority from U.S. Provisional Application Ser. No. 61/746,214, filed Dec. 27, 2012, which is hereby incorporated by reference in its entirety.

FIELD OF THE INVENTION

The present invention is directed to a process for producing oil. In particular, the present invention is directed to a process for producing a heavy oil or bitumen having a measurable total acid number.

BACKGROUND OF THE INVENTION

Large deposits of heavy oil or bitumen are present in some areas of the world. These deposits offer the opportunity to capture large quantities of oil, however, the nature of the heavy oil or bitumen renders recovering the oil difficult. Heavy oil and bitumen contain more high molecular weight hydrocarbons such as asphaltenes and resins than light crudes, which renders the heavy oil/bitumen much more viscous than light crudes. Viscous heavy oil or bituminous crudes are more difficult to mobilize and produce from a subterranean formation than crudes of low viscosity since the viscous crudes do not flow easily.

Heat has been used for enhancing oil production from subterranean heavy oil and bitumen-containing formations. Heat applied to the heavy oil or bitumen within the formation reduces the viscosity of heavy oil or bitumen so the oil in place in the formation may flow more freely and be mobilized for production.

Steam flooding is one method that is commonly used to provide heat to subterranean heavy oil and bitumen-containing formations. Steam is injected into a heavy oil or bitumen-containing subterranean formation through an injection well extending into the formation, and is contacted with the oil in place in the formation to heat the oil, mobilizing the oil for production from the formation. Steam provides sensible heat and latent heat of condensation to the oil in the formation to reduce the viscosity of the oil. Furthermore, the water condensed from the steam may form an oil-in-water emulsion with the oil in the formation, where the emulsion has a viscosity on the same order of magnitude as water and substantially less than the oil itself, where the oil-in-water emulsion may be mobilized for production from the formation. The reduced viscosity oil and the oil-in-water emulsion are then produced from the formation.

Steam flooding may be effected by injecting the steam into a heavy oil or bituminous subterranean formation through one or more injection wells for a period of time to lower the viscosity of the oil near the injection wellbore, then stopping the injection of steam and pumping the reduced viscosity oil from the formation through the well used to inject the steam into the formation. When the oil production drops off, steam injection may be resumed to heat more oil in the formation, followed by further production. Steam flooding may also be effected by continuously injecting the steam into a heavy oil or bitumen-containing subterranean formation through one or more vertical injection wells and continuously producing oil from the formation through one or more vertical production wells.

Steam-Assisted-Gravity-Drainage (“SAGD”) is a method for producing heavy oil or bitumen from a heavy oil or bitumen-containing subterranean formation that utilizes gravity in combination with steam induced viscosity reduction of bitumen or heavy oil to recover oil from the formation. A paired injection well and production well are drilled so that portions of the wells that are in contact with the oil-containing portion of the formation extend horizontally through the formation, where the horizontally extending portions of the paired injection well and production well are aligned in parallel—the horizontally extending portion of the production well located from 2-10 meters below the horizontally extending portion of the injection well. Steam is injected into the formation through the injection well, heating the bitumen or heavy oil around the injection well to reduce the viscosity thereof and to form an oil-in-water emulsion having reduced viscosity relative to the bitumen or heavy oil in the formation. The reduced viscosity bitumen or heavy oil and the oil-in-water emulsion are mobilized and fall towards the production well, which produces the mobilized oil and emulsion.

When conducting a SAGD process, a steam chamber is formed extending from the injection well upwards into the formation. As steam is injected into the formation, the bitumen or heavy oil is mobilized and drains towards the production well, leaving freed pore space in the formation which is filled with further steam being injected into the formation. As steam is injected into the formation it traverses the steam chamber to contact new bitumen or heavy oil at the edges of the steam chamber, mobilizing the new bitumen or heavy oil for production from the production well.

Patent application publication WO 2009/108423 A1 discloses a method of improving the recovery of bitumen from a subterranean formation using a SAGD process in which steam and a volatile amine, steam and a volatile amine and ammonia, or high quality steam (having a vapor quality of at least 0.7) and ammonia are injected into the formation. The volatile amine, volatile amine plus ammonia, or ammonia in combination with the high quality steam traverse the steam chamber to contact bitumen at the edge of the steam chamber. The volatile amine and/or ammonia can potentially react with naphthenic acids in the bitumen to form oil-emulsifying soaps. These soaps may combine with condensed water to form a low viscosity oil-in-water emulsion that may drain to the production well for recovery from the formation.

Injection of steam into the formation from the injection well in a SAGD process or a combination of high quality steam and ammonia, amines, or amines plus ammonia does not mobilize all of the bitumen or heavy oil in the steam chamber. Significant quantities of residual oil are left in place within the steam chamber that are not recovered.

Improvements to steam-based bitumen or heavy oil recovery processes are desirable. In particular, improvements to steam-based processes for recovery of bitumen or heavy oil that improve recovery of residual oil are desirable.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a process for producing oil comprising injecting an oil recovery formulation comprising ammonia and steam into a subterranean oil-bearing formation comprising an oil or bitumen having a total acid number (“TAN”) of at least 0.1, wherein the steam has a vapor quality of from greater than 0 to less than 0.7; and producing oil or bitumen from the formation after injection of the oil recovery formulation into the formation. In one aspect, the process further comprises the steps of forming a steam chamber in the oil-bearing formation, injecting the oil recovery formulation into the steam chamber in the formation, and recovering residual oil from the steam chamber after injecting the oil recovery formulation into the formation.

In another aspect, the present invention is directed to a process for producing oil, comprising injecting steam having a vapor quality of from greater than 0 to less than 0.7 into an oil-bearing formation comprising an oil or bitumen having a TAN of at least 0.1; injecting ammonia into the oil bearing formation to contact the steam and form an oil recovery formulation comprising ammonia and steam having a vapor quality of from greater than 0 to less than 0.7; contacting the oil recovery formulation with oil in the formation; and producing oil from the formation after contacting the oil with the oil recovery formulation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an oil production system that may be used to practice the process of the present invention.

FIG. 2 illustrates an oil production system that may be used to practice the process of the present invention.

FIG. 3 illustrates a processing facility that may be used in the practice of the process of the present invention.

FIG. 4 illustrates an oil production system that may be used to practice the process of the present invention, depicting an oil recovery formulation being injected into an oil-bearing formation.

FIG. 5 illustrates an oil production system that may be used to practice the process of the present invention, depicting production of oil from the formation.

FIG. 6 illustrates an oil production system that may be used to practice the process of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to a process for enhancing the recovery of oil from a subterranean formation containing heavy oil or bitumen. An oil recovery formulation comprising ammonia and low quality steam—in particular, steam having a vapor quality of less than 0.7—may be injected into the formation and oil may be produced from the formation after injection of the oil recovery formulation into the formation. The combination of ammonia and low quality steam in the oil recovery formulation produces ammonium hydroxide in the liquid phase aqueous condensate portion of the low quality steam so that the ammonium hydroxide is present in the oil recovery formulation as the oil recovery formulation is injected into the formation. The ammonium hydroxide may react with petroleum acids, e.g. naphthenic acids, in the bitumen or heavy oil in the immediate vicinity of the injecting well to form an oil-emulsifying soap that promotes the formation of an oil-in-water emulsion with condensed water from the steam, where the oil-in-water emulsion may have a significantly reduced viscosity and interfacial tension relative to the bitumen or heavy oil in the formation. The steam may also provide sensible and latent heat to bitumen or heavy oil in the immediate vicinity of the injecting well to reduce the viscosity of the bitumen or heavy oil in the immediate vicinity of the injecting well. The reduced viscosity bitumen or heavy oil and the oil-in-water emulsion may be mobilized in the formation for production from the formation.

Alternatively, the process of the present invention may comprise injecting low quality steam—in particular, steam having a vapor quality of less than 0.7—and gaseous ammonia or liquid ammonia separately into a heavy oil or bitumen containing formation in which the heavy oil or bitumen has a TAN of at least 0.1, and mixing the injected steam and ammonia in the immediate vicinity of the injecting well. The mixture of low quality steam and ammonia produces or contains ammonium hydroxide as a result of interaction with liquid phase water with ammonia, where the ammonium hydroxide may react with petroleum acids in the bitumen or heavy oil in the immediate vicinity of the injecting well to form an oil-emulsifying soap that promotes the formation of an oil-in-water emulsion that is less viscous and has lower interfacial tension than the heavy oil or bitumen in the formation and that is mobilized for production from the formation. The steam also provides sensible and latent heat to bitumen or heavy oil in the immediate vicinity of the injecting well to reduce the viscosity and mobilize the bitumen or heavy oil for production. The mobilized oil and oil-in-water emulsion may be produced from the formation.

The process of the present invention is suited for improving recovery of oil in a SAGD process relative to conventional SAGD processes. As noted above, significant quantities of oil are left as residual oil in the steam chamber formed in a SAGD process. SAGD typically fails to recover about 45% of the initial bitumen or heavy oil in a formation.

In conventional SAGD processes, high quality steam is injected through the steam chamber to the edge of the steam chamber where the steam contacts bitumen, cools and provides sensible and latent heat to the bitumen at the edge of the steam chamber, reducing the viscosity and mobilizing the bitumen for production. The mobilized bitumen falls to the producing well, expanding the steam chamber as it is removed from the formation. A substantial portion of the heat provided by the high quality steam to the bitumen at the edge of the steam chamber is latent heat, which is not provided to residual oil left in the steam chamber since the steam is dry when passing through the steam chamber. Therefore, a substantial amount of the residual oil in the steam chamber is not mobilized for production by injection of high quality steam into the formation.

WO 2009/108423 A1 discloses a process for improving the recovery of bitumen in a SAGD process by injecting a mixture of high quality steam and ammonia, an amine and ammonia, or an amine into a subterranean bitumen formation. The process of WO 2009/108423 does not promote substantial recovery of residual oil in the steam chamber when high quality steam and ammonia are used in the process. The high quality steam is dry as it passes through the steam chamber, and fails to provide latent heat of condensation to lower the viscosity of the residual oil. Further, production of a mobile oil-in-water emulsion of the residual oil in the steam chamber is avoided since emulsion-inducing ammonium hydroxide is not formed in the steam chamber by reaction of ammonia with liquid phase water. The high quality steam is dry as it passes through the steam chamber and insufficient liquid phase water condensate is present in the steam chamber to form ammonium hydroxide with the injected ammonia sufficient to produce recoverable quantities of an oil-in-water emulsion of the residual oil.

The process of the present invention may promote recovery of residual oil from the steam chamber. Unlike the process disclosed in WO 2009/108423, ammonium hydroxide is present in the immediate vicinity of the injecting well, and therefore, in the steam chamber in a SAGD process, when the oil recovery formulation or the mixture of separately injected ammonia and low quality steam is injected into the formation. The ammonium hydroxide is present in the immediate vicinity of the injecting well and in the steam chamber because a sufficient quantity of water condensate is present to react with the ammonia to form ammonium hydroxide either in the oil recovery formulation prior to injecting the oil recovery formulation into the formation or immediately upon mixing separately injected ammonia and low quality steam into the formation. The ammonium hydroxide may react with petroleum acids of the residual oil in the steam chamber to form an oil-emulsifying soap that promotes the formation of a low viscosity oil-in-water emulsion with the water condensate of the low quality steam. The oil-in-water emulsion may be mobilized for production from the formation due to its low viscosity and low interfacial tension.

The process of the present invention is also suited for improving the oil recovery in a cyclic steam stimulation (CSS) process relative to a conventional CSS process. Further, the process of the present invention is also suited for improving the oil recovery in a vertical steam drive (VSD) process relative to a conventional VSD process.

The oil recovery formulation used in the process of the present invention is comprised of ammonia and steam, where the steam used is of low quality, specifically the steam has a vapor quality of less than 0.7. As used herein, “vapor quality” is defined as the fraction of the mass of a saturated fluid that is vapor. Vapor quality is defined according to the following equation: χ=[m_vapor/(M_vapor+M_liquid)], where χ is the vapor quality and m is mass (measured in the same units for each m). Fluids that are not saturated fluids, such as compressed fluids and superheated fluids, do not have a defined vapor quality. The vapor quality of steam may be calculated from the temperature and pressure of the steam according to conventional methods known to those of ordinary skill in the art. The steam of the oil recovery formulation may have a vapor quality of less than 0.7, or from greater than 0 to less than 0.7, or from 0.05 to 0.65, or from 0.25 to 0.6.

The ammonia of the oil recovery formulation is preferably gaseous anhydrous ammonia. Alternatively, the ammonia of the oil recovery formulation may be contained in a gaseous ammonia-steam mixture (prior to being mixed with the low quality steam of the oil recovery formulation) containing up to 30 wt. % steam, or up to 20 wt. % steam, or up to 10 wt. % steam, or up to 5 wt. % steam. Alternatively, but less preferably, the ammonia may be a pressurized anhydrous ammonia liquid, or may be contained in an aqueous ammonia solution containing up to 35% ammonia by mass.

The oil recovery formulation may contain ammonia in an amount effective to form sufficient ammonium hydroxide to react with petroleum acids in the oil to form one or more surfactants in a quantity sufficient to mobilize a portion of the oil in the formation. The oil recovery formulation may be comprised of from 0.001 wt. % to 90 wt. % ammonia. Preferably the amount of ammonia in the oil recovery formulation is at or near a minimum amount effective to form sufficient ammonium hydroxide to react with petroleum acids in the oil to form one or more surfactants in a quantity sufficient to mobilize a portion of the oil in the formation, thereby maximizing the amount of steam and thermal energy provided by the oil recovery formulation to the formation for mobilization of the oil. In this embodiment of the process of the present invention, the oil recovery formulation may contain from 50 parts per million (ppm) to 50,000 ppm by weight of ammonia, or from 100 ppm to 10,000 ppm by weight of ammonia.

The oil recovery formulation used in the process of the present invention may contain components other than low quality steam and ammonia. The oil recovery formulation may contain an anionic surfactant or a non-ionic surfactant that may form an oil-emulsifying soap upon contacting bitumen or heavy oil in a formation, promoting the formation of a low viscosity oil-in-water emulsion with condensed water from the oil recovery formulation and thereby mobilizing the bitumen or heavy oil for production from the formation. An anionic surfactant or non-ionic surfactant utilized in the oil recovery formulation should be stable at the temperature of the steam utilized in the oil recovery formulation. Anionic surfactants that may be utilized in the oil recovery formulation may be selected from the group of high temperature stable surfactants consisting of an alpha olefin sulfonate compound, an internal olefin sulfonate compound, a branched alkyl benzene sulfonate compound, a propylene oxide sulfate compound, an ethylene oxide sulfate compound, an ethylene oxide-propylene oxide sulfate compound, and blends thereof. Amine compounds may be absent from the oil recovery formulation, and the oil recovery formulation may be free of amine compounds. In an embodiment of a process of the present invention, the oil recovery formulation may consist essentially of ammonia and steam having a vapor quality of less than 0.7.

The oil recovery formulation may be produced by mixing ammonia and a low quality steam having a vapor quality of less than 0.7, or having a vapor quality of from greater than 0 to less than 0.7, or from 0.05 to 0.65, or from 0.25 to 0.6. The ammonia and the low quality steam may be contacted and mixed to form the oil recovery formulation prior to introducing the oil recovery formulation to a well for injection into a subterranean formation containing bitumen or heavy oil. Alternatively, the ammonia and low quality steam may be contacted and mixed upon introduction of the ammonia and the low quality steam to a well for injection into a subterranean formation containing bitumen or heavy oil, or may be contacted and mixed within the injection well prior to injection of the oil recovery formulation into the formation.

In another embodiment, the ammonia and low quality steam may be injected separately into a subterranean formation containing bitumen and heavy oil and mixed to form the oil recovery formulation in the immediate vicinity of the injection well. In one embodiment of the process of the present invention, the injection well may have a conduit extending from the wellhead to perforations or openings in the well at a position located in the formation through which the low quality steam may be injected and a separate conduit extending from the wellhead to perforations or openings in the well at a position located in the formation through which the ammonia may be injected into the formation, where the perforations or openings through which the steam is injected into the formation and the perforations or openings through which the ammonia is injected into the formation are positioned in the well to ensure that the steam and ammonia are mixed together upon injection into the formation through the well. In one embodiment, perforations or openings or a set of perforations or openings in the well for injecting the steam into the formation and perforations or openings or a set of perforations or openings in the well for injecting ammonia into the formation are positioned to alternate along a portion of the injecting well within the formation.

In the process of the present invention, the oil recovery formulation, or components thereof, is/are introduced into an oil-bearing formation. The oil-bearing formation comprises oil that may be separated and produced from the formation after contact and mixing with the oil recovery formulation. The oil of the oil-bearing formation is a heavy oil or bitumen having a TAN of at least 0.1. “TAN”, as used herein, refers to a total acid number of a bitumen or heavy oil expressed as milligrams (“mg”) of KOH per gram of the heavy oil or bitumen as may be determined by ASTM Method D664.

The oil contained in the oil-bearing formation may have a dynamic viscosity under formation conditions (in particular, at temperatures within the temperature range of the formation) of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP). The oil contained in the oil-bearing formation may have a dynamic viscosity under formation temperature conditions of from 1 to 10000000 mPa s (1 to 10000000 cP). Typically, the heavy oil or bitumen in the formation may have a dynamic viscosity of at least 100 mPa s (100 cP), or at least 500 mPa s (500 cP), or at least 1000 mPa s (1000 cP).

The oil-bearing formation is a subterranean formation. The subterranean formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6000 meters, or from 100 meters to 4000 meters, or from 200 meters to 2000 meters under the earth's surface. The subterranean formation may be a subsea subterranean formation.

The porous matrix material may be a consolidated matrix material in which at least a majority, and preferably substantially all, of the rock and/or mineral that forms the matrix material is consolidated such that the rock and/or mineral forms a mass in which substantially all of the rock and/or mineral is immobile when oil, the oil recovery formulation, water, or other fluid is passed therethrough. At least 95 wt. % or at least 97 wt. %, or at least 99 wt. % of the rock and/or mineral may be immobile when oil, the oil recovery formulation, water, or other fluid is passed therethrough so that any amount of rock or mineral material dislodged by the passage of the oil, oil recovery formulation, water, or other fluid is insufficient to render the formation impermeable to the flow of the oil recovery formulation, oil, water, or other fluid through the formation. Alternatively, the porous matrix material may be an unconsolidated matrix material in which at least a majority, or substantially all, of the rock and/or mineral that forms the matrix material is unconsolidated. The formation may have a permeability of from 0.0001 to 15 Darcys, or from 0.001 to 1 Darcy. The rock and/or mineral porous matrix material of the formation may be comprised of sandstone and/or a carbonate selected from dolomite, limestone, and mixtures thereof—where the limestone may be microcrystalline or crystalline limestone and/or chalk.

Oil in the oil-bearing formation may be located in pores within the porous matrix material of the formation. The oil in the oil-bearing formation may be immobilized in the pores within the porous matrix material of the formation, for example, by capillary forces, by interaction of the oil with the pore surfaces, by the viscosity of the oil, or by interfacial tension between the oil and water in the formation.

The oil-bearing formation may also be comprised of water, which may be located in pores within the porous matrix material. The water in the formation may be connate water, water from a secondary or tertiary oil recovery process water-flood, or a mixture thereof. The water in the oil-bearing formation may be positioned to immobilize petroleum within the pores. Contact of the oil recovery formulation with the oil and water in the formation may mobilize the oil in the formation for production and recovery from the formation by freeing at least a portion of the oil from pores within the formation by reducing interfacial tension between water and oil in the formation and by reducing the viscosity of the oil in the formation.

In some embodiments, the oil-bearing formation may comprise unconsolidated sand and water. The oil-bearing formation may be an oil sand formation. Unconsolidiated oil sand material of the oil sand formation may have a tensile strength of about 0 Pa. In some embodiments, the oil may comprise between about 1 wt. % and about 16 wt. % of the oil/sand/water mixture, the sand may comprise between about 80 wt. % and about 85 wt. % of the oil/sand/water mixture, and the water may comprise between about 1 wt. % and about 16 wt. % of the oil/sand water mixture. The sand may be coated with a layer of water with the oil being located in the void space around the wetted sand grains.

Referring now to FIGS. 1 and 2, oil production systems 100 are illustrated that may be used to practice one or more embodiments of a SAGD process in accordance with the process of the present invention. An oil production system 100 includes an oil-bearing formation 105 that may be comprised of oil-bearing portions 104, 106, and 108 located beneath an overburden 102. The oil production system 100 may include a first well 132 through which the oil recovery formulation, or components thereof, may be injected into the formation 105, and a second well 112 through which oil, water, and optionally gas, may be produced. The oil production system may also include a water storage facility 116, an ammonia storage facility 118, an oil recovery formulation storage facility 130, an oil storage facility 134, and a gas storage facility 136.

The oil production system 100 may also include a processing facility 110. The processing facility 110 may include a water processing system 120 and a separation unit 122. Referring now to FIG. 3, the water processing system 120 may be comprised of a water purification unit 202 comprising one or more particulate filters 204, which may include an ultrafiltration membrane; one or more ionic filtration units 206 such as a nanofiltration membrane unit and/or a reverse osmosis unit; and/or one or more ion exchange systems 208 for removing ions from water. Source water may enter the water purification unit 202 through line 212 and proceed through the particulate filters 204 for removal of suspended solids from the source water, and then proceed through the ionic filtration unit 206 and/or the ion exchange system 208 for removal of ions, particularly multivalent cations, from the water. The water processing system may also be comprised of a boiler 210 that is fluidly operatively coupled to the water purification unit 202 via line 214 to receive purified water from the water purification unit. The boiler 210 may be configured to produce low quality steam having a vapor quality of from greater than 0 to less than 0.7, or from 0.05 to 0.65, or from 0.25 to 0.6, from the purified water produced by the water purification unit, where the steam may be exported from the water processing system 120 via line 216.

The separation unit 122 of the processing facility 110 may be designed to separate oil, gas, and an aqueous phase produced from the formation. The separation unit 122 may be comprised of a 2-phase separator 230 and a water knockout vessel 232. The 2-phase separator 230 of the separation unit 122 may be fluidly operatively coupled to the second well by conduit 234 to receive oil, gas, and an aqueous solution produced from the formation by the second well. The produced oil and aqueous solution may be separated from produced gas in the 2-phase separator 230, where the separated produced gas may be exported from the 2-phase separator and separation unit 122 through conduit 236. The produced oil and aqueous solution may be provided from the 2-phase separator 230 to the water knockout vessel 232 via conduit 238. The produced oil may be separated from the aqueous solution in the water knockout vessel, where separation aids such as a demulsifier and/or a brine solution may be provided to the water knockout vessel through inlet 240 to aid in the separation of the produced oil from the aqueous solution in accordance with methods known to those skilled in the art of separating oil and aqueous phases from a fluid containing an oil phase and an aqueous phase. The produced oil may be exported from the water knockout vessel 232 and the separation unit 122 through conduit 242, and the aqueous solution may be exported from the water knockout vessel 232 and the separation unit 122 through conduit 244.

Referring back to FIGS. 1 and 2, the first well 132 and the second well 112 extend from the surface 140 into one or more of the oil-bearing portions 104, 106, and 108 of the subterranean oil-bearing formation 105. A subsurface portion 142 of the first well 132 and a subsurface portion 144 of the second well may traverse one or more oil-bearing portions of the formation 105. The subsurface portion 144 of the second, producing, well 112 may be located below the subsurface portion 142 of the first, injecting, well 132. The subsurface portions 142 and 144 of the first and second wells 132 and 112, respectively, may be positioned transverse to portions 146 and 148 of the first and second wells 132 and 112, respectively, that extend from the surface 140 to the respective subsurface portions 142 and 144 of the wells. The subsurface portion 142 of the first well 132 and the subsurface portion 144 of the second well 112 may extend horizontally through the formation, and the horizontally extending subsurface portion 144 of the second well 112 may extend parallel to and below the horizontally extending subsurface portion 142 of the first well 132.

The vertical spacing between the horizontal subsurface portion 142 of the first well 132 and the horizontal subsurface portion 144 of the second well 112 may be from 2 meters to 150 meters, or from 5 meters to 100 meters. The horizontal subsurface portion 142 of the first well 132 and the horizontal subsurface portion 144 of the second well 112 may have a length of from 25 meters to 2000 meters, or from 50 meters to 1000 meters, or from 100 meters to 500 meters. The horizontal subsurface portion 144 of the second well 112 is preferably as long as, or longer than, the horizontal subsurface portion 142 of the first well 132.

As shown in FIG. 1, a toe section 150 of the subsurface portion 142 of the first well 132 may be aligned with a heel section 152 of the subsurface portion 144 of the second well. Alternatively, as shown in FIG. 2, a heel section 154 of the subsurface portion 142 of the first well 132 may be aligned with the heel section 152 of the subsurface portion 144 of the second well 112. Referring again to FIGS. 1 and 2, although the wells 132 and 112 are shown with an abrupt right angle transition from vertical to horizontal, in some embodiments wells 132 and 112 may have a smooth transition from vertical to deviated to horizontal, for example with a smooth curved radius.

Referring now to FIGS. 1, 2, and 3, in a process of the present invention the oil recovery formulation comprising ammonia and steam having a vapor quality of from greater than 0 to less than 0.7, or components thereof, is/are injected into one or more oil-bearing portions 104, 106, or 108 of the oil-bearing formation 105 comprising heavy oil or bitumen through the first, injecting, well 132. The oil recovery formulation may be provided to the first well 132 from an oil recovery formulation storage facility 130 that is fluidly operatively coupled to the first well via conduit 129 to provide the oil recovery formulation to the first well. Steam may be provided to the oil recovery formulation storage facility 130 by providing source water from the water storage facility 116 to the water processing unit 120 of the processing facility 110 via conduit 212, where particulates and ions are removed from the source water in the water purification unit 202 and steam having a vapor quality of from greater than 0 to less than 0.7 is formed in the boiler 210 and provided to the oil recovery formulation storage facility via conduit 216. Ammonia may be provided to the oil recovery formulation storage facility 130 from the ammonia storage facility 118 via conduit 160. Alternatively, steam having a vapor quality of from greater than 0 to less than 0.7 may be provided directly from the boiler 210 to the first well 132 and ammonia may be provided directly from the ammonia storage facility to the first well 132 to form the oil recovery formulation near or within the first well, or to be injected into the formation as separate components that are mixed in the formation in the immediate vicinity of the first well to form the oil recovery formulation—in which cases the oil recovery formulation storage facility 130 may be excluded from the system. The amount of ammonia included in the oil recovery formulation injected into the formation, or injected into the formation to form the oil recovery formulation, may be from 0.001 wt. % to 90 wt. % of the oil recovery formulation, or may be from 50 parts per million (ppm) by weight to 50,000 ppm by weight of the oil recovery formulation.

The oil recovery formulation, or components thereof, may be injected into the formation 105 through the subsurface portion 142 of the first well 132. The subsurface portion 142 of the first well 132 may have perforations or openings along the length of the portion 142 through which the oil recovery formulation, or components thereof, may be injected into the formation.

The oil recovery formulation, or components thereof, may be injected into the formation under sufficient pressure to introduce the oil recovery formulation, or its components, into the formation. The oil recovery formulation, or its components, may be injected into the formation at a pressure above the initial pressure of the formation at the injection point, and may be injected at a pressure ranging from immediately above the initial pressure of the formation up to the fracture pressure of the formation, or even above the fracture pressure of the formation. In an embodiment of the process of the present invention, the oil recovery formulation may be injected into the formation at a pressure of from immediately above the formation pressure to 37,000 kPa above the initial pressure of the formation.

Upon injection of the oil recovery formulation into the formation 105, the oil recovery formulation may contact and mix with oil within the formation. If one or more of the components of the oil recovery formulation are injected separately, the components of the oil recovery formulation may be contacted and mixed in the immediate vicinity of the first, injecting, well 132 to form the oil recovery formulation, which then may contact and mix with oil in the formation. Contacting the oil recovery formulation with oil in the formation may reduce the viscosity of the oil, for example by heating the oil with the sensible heat and the latent heat of condensation of the steam in the oil recovery formulation. Contacting the oil recovery formulation with the oil in the formation may also induce the formation of an oil-in-water emulsion having a viscosity of the same magnitude as water by contact with water present in, or condensed from, the low quality steam of the oil recovery formulation Ammonium hydroxide present in the oil recovery formulation as a result of contact of ammonia and water present in, or condensed from, the low quality steam may react with the oil to form an oil emulsifying soap that may enhance the formation of the oil-in-water emulsion.

The oil in the formation may be mobilized for production by contact with the oil recovery formulation. The reduction of the oil viscosity by exchange of thermal energy with the steam of the oil recovery formulation and the formation of the low viscosity oil-in-water emulsion may mobilize the oil contacted by the oil recovery formulation relative to oil initially present in the formation. The mobilized reduced viscosity oil and the oil-in-water emulsion may be freed to fall toward the second, production, well 112, from which the oil and the emulsion may be produced from the formation.

The process of the present invention may comprise forming a steam chamber 170 in the formation 205; injecting the oil recovery formulation or the components of the oil recovery formulation into the steam chamber 170; and recovering residual oil from the steam chamber after injecting the oil recovery formulation or the components of the oil recovery formulation into the steam chamber. The steam chamber 170 may be formed by injecting steam into the formation through the first well 132 and the second well 112 for a first period of time. The steam injected in this first period of time is preferably high quality dry steam having a vapor quality of at least 0.9. The steam injected in the first period of time reduces the viscosity of oil in the immediate vicinity of the first well 132 and the second well 112. Steam injection may be stopped from the second well 132 after the first period of time, and reduced viscosity oil may be produced from the second well 132. Steam may be injected again through the second well to reduce the viscosity of more oil in the formation, and then the additional reduced viscosity oil may be recovered from the second well. Steam injection through the first and second wells 132 and 112, and production of oil from the second well 112 may be continued in this manner until a steam chamber 170 is formed in the formation. The steam chamber has a reduced quantity of oil therein (the “residual oil”) relative to the amount of oil present in the formation at the boundary of the steam chamber and portions of the formation outside of the steam chamber.

The oil recovery formulation, or components thereof, may be injected into the steam chamber 170 through the subsurface portion 142 of the first well 132. The oil recovery formulation may contact the residual oil in the steam chamber 170 and mobilize the residual oil as described above relative to oil in the formation. The oil recovery formulation is suited to mobilize the residual oil in the steam chamber since the steam is low vapor quality steam containing a substantial amount of condensed water containing ammonium hydroxide that forms oil emulsifying soaps upon contacting the residual oil, where the condensed water may then form an oil-in-water emulsion that is mobilized for production from the formation. The mobilized residual oil may fall from the steam chamber 170 to the second well 112 for production from the formation.

A portion of the oil recovery formulation may pass through the steam chamber 170 to the interface of the steam chamber with portions of the formation outside of the steam chamber. This portion of the oil recovery formulation may mobilize oil at the interface of the steam chamber and the portions of the formation outside the steam chamber for production from the formation as described above. The mobilized “interface” oil may fall from the interface to the second well 112 for production from the formation.

The mobilized oil, water, and optionally gas, may be produced from the formation through the second well 112 by conventional oil production processes. The well 112 may include conventional mechanisms for producing oil from a formation, including lift pumps, lift gases, and/or a compressor for injecting gas into the formation to produce the oil, water, and optionally gas from the formation.

Referring now to FIGS. 1, 2, and 3, the oil, water, and gas produced from the formation through the second well may be processed and separated. The second well 112 may be fluidly operatively coupled to the 2-phase separator 230 of the separation unit 122 via conduit 234. As described above, the produced oil, produced gas, and an aqueous solution may be separated in the separation unit 122. The separated produced oil may be provided from the water knockout vessel 232 of the separation unit to the oil storage facility 134 via conduit 242. The separated produced gas may be provided from the 2-phase separator 230 of the separation unit 122 to the gas storage facility 136 via conduit 236. The separated aqueous solution may be provided from the water knockout vessel 232 to the water storage facility 116 via conduit 244.

The process of the present invention may also be utilized in a cyclic steam stimulation (“CSS”) oil recovery process. Referring now to FIGS. 4 and 5, an oil production system utilizing a single well for injection and production according to a CSS process in accordance with the process of the present invention is shown. The system 300 may be similar in some respects to the system 100 described above with reference to FIGS. 1 and 2 and with the water processing system of FIG. 2. Accordingly, the system 300 may be understood with reference to FIGS. 1, 2, and 3, where like numerals are used to indicate like components that will not be described again in detail.

As shown in FIG. 4, an oil recovery formulation comprised of ammonia and low quality steam, or components thereof, may be injected into a formation 105 through well 312. The oil recovery formulation may be provided to the well 312 from an oil recovery formulation storage facility 130 via conduit 302, where ammonia may be provided to the oil recovery formulation storage facility 130 from an ammonia storage facility 118 via conduit 160, and steam may be provided to the oil recovery formulation storage facility via conduit 216 from a water processing system 120 including a water purification system and a boiler for producing steam having a vapor quality of from greater than 0 to less than 0.7 from water provided from a water storage facility 116 via conduit 212. Alternatively, the components of the oil recovery formulation may be provided separately to the well 312 from the ammonia storage facility 118 and the water processing system 120 of the processing facility 110 for mixing at the well, within the well, or upon injection into the formation, as described above.

The oil recovery formulation, or components thereof, may be injected into the formation 105 through the well 312 to contact and mix with heavy oil or bitumen in the formation, as shown by arrows 314. The oil recovery formulation may reduce the viscosity of the heavy oil or bitumen upon contact by heating the heavy oil or bitumen, as described above, and thereby mobilize the oil for recovery from the formation. The oil recovery formulation may also induce the formation of an oil-in-water emulsion by the formation of oil-emulsifying soaps produced by reaction of ammonium hydroxide with petroleum acids in the oil or bitumen and thereby form and mobilize an oil-in-water emulsion for production from the formation.

The oil recovery formulation, or components thereof, may be injected into the formation through the well 312 for a first period of time after which injection of the oil recovery formulation, or components thereof, may be ceased. The oil recovery formulation may be allowed to soak in the formation after cessation of injection of the oil recovery formulation, or the components thereof.

Then, as shown in FIG. 5, the mobilized oil, water, and optionally gas, may be produced from the formation through the well 312. The mobilized oil, water, and optionally gas, may be drawn through the formation as shown by arrows 316 for production from the well. The well 312 may include conventional mechanisms for producing oil from a formation, including lift pumps, lift gases, and/or a compressor for injecting gas into the formation to produce the oil, water, and optionally gas from the formation.

The oil, water, enhanced oil recovery formulation, and gas produced from the well 312 may be separated in the processing facility 110 and stored as described above.

In one embodiment of a CSS process in accordance with the process of the present invention, prior to injecting the oil recovery formulation into the formation and subsequently recovering mobilized oil, water, and optionally gas therefrom, high quality steam having a vapor quality of at least 0.7, or at least 0.9, may be injected into the formation 105 through well 312 to contact and mix and soak with heavy oil or bitumen in the formation to mobilize the heavy oil or bitumen, and then the mobilized oil may be recovered through well 312. The cycle of injection of high quality steam into the formation; contacting, mixing, and soaking the high quality steam with the bitumen or heavy oil to mobilize the oil, and recovery of the mobilized oil from the well may be effected one or two or more times prior to injecting the oil recovery formulation into the formation; contacting, mixing, and soaking the oil recovery formulation with bitumen or heavy oil in the formation to mobilize the oil in the formation; and recovering the mobilized oil from the well through which the oil recovery formulation was injected into the formation. Use of the oil recovery formulation as described above after CSS oil recovery using high quality steam enables recovery of residual oil in the formation.

The process of the present invention may also be utilized in a vertical steam drive (“VSD”) oil recovery process. Referring now to FIG. 6, an oil production system 400 is illustrated that may be used to practice one or more embodiments of a vertical steam drive (VSD) process in accordance with the process of the present invention. The system may be similar in some respects to the system 100 described above with respect to FIGS. 1 and 2 and the water processing system as shown in FIG. 3. Accordingly, the system 400 may be understood with reference to FIGS. 1, 2, and 3, where like numerals are used to indicate like components that will not be described again in detail.

As shown in FIG. 6, an oil recovery formulation comprised of ammonia and low quality steam, or components thereof, may be injected into a formation 105 through a first well 432. The oil recovery formulation may be provided to the first well 432 from an oil recovery formulation storage facility 130 via conduit 129, where ammonia may be provided to the oil recovery formulation storage facility 130 from an ammonia storage facility 118 via conduit 160, and steam may be provided to the oil recovery formulation storage facility via conduit 216 from a water processing system 120 including a water purification system and a boiler for producing steam having a vapor quality of from greater than 0 to less than 0.7 from water provided from a water storage facility 116 via conduit 212. Alternatively, the components of the oil recovery formulation may be provided separately to the first well 432 from the ammonia storage facility 118 and the water processing system 120 for mixing at the first well, within the first well, or upon injection into the formation 105, as described above.

The oil recovery formulation, or components thereof, may be injected into the formation 105 through the first well 432 to contact and mix with heavy oil or bitumen, as described above, and thereby mobilize the oil for recovery from the formation. The oil recovery formulation may reduce the viscosity of the heavy oil or bitumen upon contact by heating the heavy oil or bitumen, as described above, and thereby mobilize the oil for recovery from the formation 105. The oil recovery formulation may also induce the formation of an oil-in-water emulsion by the formation of oil-emulsifying soaps produced by reaction of ammonium hydroxide with petroleum acids in the oil or bitumen and thereby form and mobilize an oil-in-water emulsion for production from the formation.

The mobilized oil may be pushed across the formation 105 from the first well 432 to the second well 412 as shown by arrows 414 and 416 by further introduction of more oil recovery formulation into the formation or by introduction of an oil immiscible drive fluid into the formation subsequent to injection of the oil recovery formulation into the formation.

The oil immiscible drive fluid may be introduced into the formation 105 through the first well 432 to force or otherwise displace the mobilized oil toward the second well 412 for production. The oil immiscible drive fluid may be configured to displace the mobilized oil through the formation 105. Suitable oil immiscible drive fluids are not first contact miscible or multiple contact miscible with oil in the formation 105. The oil immiscible drive fluid may be selected from the group consisting of an aqueous polymer fluid, water, carbon dioxide at a pressure below its minimum miscibility pressure, nitrogen at a pressure below its minimum miscibility pressure, air, and mixtures of two or more of the preceding.

Suitable polymers for use in an aqueous polymer fluid may include, but are not limited to, polyacrylamides, partially hydrolyzed polyacrylamides, polyacrylates, ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohols, polystyrene sulfonates, polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane sulfonate), combinations thereof, or the like. Examples of ethylenic copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum, guar gum, alginates, and alginic acids and their salts. In some embodiments, polymers may be crosslinked in situ in the formation 105. In other embodiments, polymers may be generated in situ in the formation 105.

The oil immiscible drive fluid may be stored in, and provided for introduction into the formation 105 from, an oil immiscible drive fluid storage facility 420 that may be fluidly operatively coupled to the first well 432 via conduit 422. The amount of oil immiscible drive fluid introduced into the formation 105 should be sufficient to drive the mobilized oil across at least a portion of the formation.

If the oil immiscible drive fluid is in liquid phase, the oil immiscible drive fluid may have a viscosity of at least the same magnitude as the viscosity of the mobilized oil at formation temperature conditions to enable the oil immiscible drive fluid to drive the mobilized oil across the formation 105 to the second well 412. The oil immiscible formulation may have a viscosity of at least 0.8 mPa s (0.8 cP) or at least 10 mPa s (10 cP), or at least 50 mPa s (50 cP), or at least 100 mPa s (100 cP), or at least 500 mPa s (500 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP) at formation temperature conditions or at 25° C. If the oil immiscible drive fluid is in liquid phase, preferably the oil immiscible drive fluid may have a viscosity at least one order of magnitude greater than the viscosity of the mobilized oil at formation temperature conditions so the oil immiscible drive fluid may drive the mobilized oil across the formation in plug flow, minimizing and inhibiting fingering of the mobilized oil through the driving plug of oil immiscible formulation.

The oil recovery formulation and the oil immiscible drive fluid may be introduced into the formation 105 through the first well 432 in alternating slugs. For example, the oil recovery formulation may be introduced into the formation 105 through the first well 432 for a first time period, after which the oil immiscible drive fluid may be introduced into the formation through the first well for a second time period subsequent to the first time period, after which the oil recovery formulation may be introduced into the formation through the first well for a third time period subsequent to the second time period, after which the oil immiscible drive fluid may be introduced into the formation through the first well for a fourth time period subsequent to the third time period. As many alternating slugs of the oil recovery formulation and the oil immiscible drive fluid may be introduced into the formation through the first well as desired.

Oil may be mobilized for production from the formation 105 via the second well 412 by introduction of the oil recovery formulation and, optionally, the oil immiscible drive fluid into the formation, where the mobilized oil is driven through the formation for production from the second well as indicated by arrows 416 by introduction of the oil recovery formulation and optionally the oil immiscible drive fluid into the formation via the first well 432.

The mobilized oil, water and optionally gas may be produced from the formation 105 through the second well 412 by conventional oil production processes. The well 412 may include conventional mechanisms for producing oil from a formation, including lift pumps, lift gases, and/or a compressor for injecting gas into the formation to produce the oil, water, and optionally gas from the formation. Oil, water and gas produced from the formation may be processed, separated, and stored as described above.

In an embodiment of a VSD process in accordance with the process of the present invention, the first well 432 may be used for introducing the oil recovery formulation and, optionally, subsequently the oil immiscible drive fluid into the formation 105 and the second well 412 may be used for producing oil, water, and optionally gas from the formation for a first time period; then the second well 412 may be used for introducing the oil recovery formulation and, optionally, subsequently the oil immiscible drive fluid into the formation 105 and the first well 432 may be used for producing oil, water, and optionally gas from the formation for a second time period; where the first and second time periods comprise a cycle. Multiple cycles may be conducted which include alternating the first well 432 and the second well 412 between introducing the oil recovery formulation and, optionally, subsequently the oil immiscible drive fluid into the formation 105, and producing oil, water, and optionally gas from the formation, where one well is introducing and the other is producing for the first time period, and then they are switched for a second time period. A cycle may be from about 12 hours to about 1 year, or from about 3 days to about 6 months, or from about 5 days to about 3 months. The oil recovery formulation may be introduced into the formation at the beginning of a cycle and the oil immiscible drive fluid may be introduced at the end of the cycle. In some embodiments, the beginning of a cycle may be the first 10% to about 80% of a cycle, or the first 20% to about 60% of a cycle, the first 25% to about 40% of a cycle, and the end may be the remainder of the cycle.

In one embodiment of a VSD process in accordance with the process of the present invention, high quality steam is injected through the first well 432 and oil is produced from the second well 412, or one or more cycles of alternately injecting high quality steam and producing oil from the first and second wells, respectively, is effected prior to injecting the oil recovery formulation into the formation and subsequently recovering mobilized oil therefrom. The high quality steam has a vapor quality of at least 0.7, and may have a vapor quality of at least 0.9, or at least 0.95, or at least 0.97. The high quality steam may be provided by the water processing system 120, where the operating conditions of the boiler 210 may be adjusted to produce the high quality steam. The high quality steam may be injected into the formation 105 through the first well 432 to contact and mix with heavy oil or bitumen in the formation to mobilize the heavy oil or bitumen, and then the mobilized oil may be recovered through the second well 412. An oil immiscible drive fluid as described above may by injected into the formation subsequent to injection of the high quality steam to drive mobilized oil across the formation 105 for production through the second well 412. Alternating slugs of the high quality steam and the oil immiscible drive fluid may be injected into the formation through the first well 412 while producing oil through the second well 432 prior to injection of the oil recovery formulation into the formation and attendant recovery of oil from the formation. Optionally, cycles of alternating slugs of high quality steam and an oil immiscible drive fluid may be injected into the formation via the first and second wells while producing oil through the second and first wells, respectively, prior to injection of the oil recovery formulation into the formation and attendant recovery of oil from the formation. Injection of the oil recovery formulation into the formation subsequent to injection of high quality steam and attendant production of mobilized oil from the formation may promote the recovery of residual oil from the formation, where the residual oil is oil left in the formation and not mobilized or recovered by the injection of the high quality steam into the formation and production of oil mobilized by the high quality steam.

The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

1. A process for producing oil, comprising:

injecting an oil recovery formulation comprising ammonia and steam into an underground oil-bearing formation comprising an oil or bitumen having a total acid number of at least 0.1, wherein the steam has a vapor quality of from greater than 0 to less than 0.7; and

producing oil or bitumen from the formation after injection of the oil recovery formulation into the formation.

2. The process of claim 1 wherein the steam of the oil recovery formulation has a vapor quality of from 0.05 to 0.65.

3. The process of claim 1 wherein the oil recovery formulation is free of amines and the oil recovery formulation is injected into the formation in the absence of amines.

4. The process of claim 1 further comprising:

forming a steam chamber in the oil-bearing formation; and

injecting the oil recovery formulation into the steam chamber in the formation.

5. The process of claim 4 further comprising recovering residual oil from the steam chamber after injecting the oil recovery formulation into the formation.

6. The process of claim 5 wherein the oil recovery formulation is injected into the steam chamber via a well and the residual oil is recovered from the steam chamber via the well.

7. The process of claim 1 wherein:

the oil recovery formulation is injected into the formation via a first well, where at least a portion of the first well traverses a portion of the formation; and

the oil or bitumen is produced from the formation via a second well, wherein the second well traverses a portion of the formation.

8. The process of claim 7 further comprising:

forming a steam chamber in the formation; and

injecting the oil recovery formulation into the steam chamber in the formation via the first well.

9. The process of claim 7 wherein a subsurface portion of the second well is positioned below a subsurface portion of the first well in the formation.

10. The process of claim 9 wherein the subsurface portion of the second well positioned below the subsurface portion of the first well in the formation is positioned transverse to a portion of the second well extending from the surface to the subsurface portion of the second well, and the subsurface portion of the first well is positioned transverse to a portion of the first well extending from the surface to the subsurface portion of the first well.

11. The process of claim 10 wherein the subsurface portion of the first well and the subsurface portion of the second well extend horizontally through the formation and the subsurface portion of the second well extends substantially parallel to the subsurface portion of the first well.

12. The process of claim 1 wherein the oil recovery formulation comprises ammonium hydroxide.

13. The process of claim 1 further comprising the step of mixing ammonia and steam to form the oil recovery formulation prior to injecting the oil recovery formulation into the formation, wherein the steam mixed with the ammonia has a vapor quality of from greater than 0 to less than 0.7.

14. The process of claim 1 further comprising injecting steam having a vapor quality of at least 0.7 into the formation and subsequently producing oil from the formation prior to injecting the oil recovery formulation into the formation.

15. The process of claim 14 wherein the steam has a vapor quality of at least 0.95.

16. A process for producing oil, comprising:

injecting steam having a vapor quality of from greater than 0 to less than 0.7 into an oil-bearing formation comprising an oil or bitumen having a total acid number of at least 0.1;

injecting ammonia into the oil-bearing formation to contact the steam within the formation and form an oil recovery formulation comprising ammonia and steam, wherein the steam has a vapor quality of from greater than 0 to less than 0.7;

contacting the oil recovery formulation with oil in the formation; and

producing oil from the formation after contacting the oil with the oil recovery formulation.