WO2020214789A1

WO2020214789A1 - Methods for the recovery of heavy hydrocarbons

Info

Publication number: WO2020214789A1
Application number: PCT/US2020/028475
Authority: WO
Inventors: Ryosuke Okuno; Upali Weerasooriya; Kwang Hoon Baek
Original assignee: Board Of Regents, The University Of Texas System
Priority date: 2019-04-16
Filing date: 2020-04-16
Publication date: 2020-10-22

Abstract

Disclosed are methods for the recovery of heavy hydrocarbons. These methods can comprise injecting steam and a volatile cyclic amine into the subterranean formation containing the heavy hydrocarbon. The heavy hydrocarbon can comprise a dense or high viscosity crude oil, bitumen, or a combination thereof. In certain cases, the heavy hydrocarbon can comprise an oil sand. Injection of the steam and the volatile cyclic amine can produce an oil-in-water emulsion in situ in the subterranean formation. The oil-in-water emulsion can comprise the heavy hydrocarbon, water, an anionic surfactant (produced in situ), and a cosolvent. The volatile cyclic amine is injected in an effective amount to (1) form the anionic surfactant in situ upon contact with the heavy hydrocarbon; and (2) provide excess unreacted volatile cyclic amine that acts as the co-solvent in the oil-in-water emulsion.

Description

Methods for the Recovery of Heavy Hydrocarbons

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Provisional Application No. 62/834,573, filed April 16, 2019, which is hereby incorporated herein by reference in its entirety.

TECHNICAL FIELD

This application relates generally to methods of producing hydrocarbons, in particular methods of producing heavy hydrocarbons using steam processes.

BACKGROUND

In some areas of the world there are large deposits of viscous or heavy crude oils and/or oil or tar sands which are located near the surface of the earth. The overburden in such areas may be nonextant but may also be as much as three hundred feet, or more. When the hydrocarbons are sufficiently shallow, the hydrocarbons may be effectively produced using strip mining or other bulk mining methods.

When hydrocarbons are too deep for bulk mining method, then the use of wells in combination with steam injection may be used to produce the hydrocarbons. One such method is known as steam flooding.

In steam flooding of an oil sand formation, for example, a pattern of wells is drilled vertically through the overburden and into the heavy oil sand, usually penetrating the entire depth of the sand. Casing is put in place and perforated in the producing interval and then steam generated at the surface is pumped under relatively high pressure down the casing and into the heavy oil formation.

In some instances the steam may be pumped for a while into all of the wells drilled into the producing formation and, after the heat has been used to lower the viscosity of the heavy oil near the well bore then the steam is removed and the heated, lowered viscosity, oil is pumped to surface, having entered the casing through the perforations. When the heat has dissipated and the heavy oil production falls off, the production is closed and the steam flood resumed. Where the same wells are used to inject steam for a while and then for production, this technique has been known as the huff and puff method or the push-pull method.

In other instances, some of the vertical wells penetrating the heavy oil sand are used to continuously inject steam while others are used to continuously produce lower viscosity oil heated by the steam. Again, when heavy oil production falls off due to lack of heat, the role of the injectors and producers can be reversed to allow injected steam to reach new portions of the reservoir and the process repeated.

In these production techniques, the steam flood can be performed at a relatively high pressure (hundreds to over one thousand pounds per square inch or PSI) so as to allow it to penetrate as deeply into the production zone as possible.

One technology for recovering heavy crude oil and bitumen is Steam Assisted Gravity Drainage (SAGD). In this method, two parallel horizontal oil wells are drilled in the formation. Each well pair (typically about 1 kilometer long and 5 meters apart) is drilled parallel and vertically aligned with one another. The upper well is known as the“injection well” and the lower well is known as the“production well”. The process begins by circulating steam in both wells so that the bitumen between the well pair is heated enough to flow to the lower production well. The freed pore space is continually filled with steam forming a“steam chamber”. The steam chamber heats and drains more and more bitumen until it has overtaken the oil-bearing pores between the well pair. Steam circulation in the production well is then stopped and injected into the upper injection well only. The cone shaped steam chamber, anchored at the production well, now begins to develop upwards from the injection well. As new bitumen surfaces are heated, the oil's viscosity is reduced, allowing it to flow downward along the steam chamber boundary into the production well by way of gravity. Steam is generally injected below the fracture pressure of the rock mass. Also, the production well is often throttled to maintain the temperature of the bitumen production stream just below saturated steam conditions to prevent steam vapor from entering the well bore and diluting oil production— this is known as the SAGD“steam trap”.

The SAGD process typically recovers about 55% of the original bitumen-in-place. Other engineering parameters affecting the economics of SAGD production include the recovery rate, thermal efficiency, steam injection rate, steam pressure, minimizing sand production, reservoir pressure maintenance, and water intrusion.

SAGD offers advantages in comparison with conventional surface mining extraction techniques and alternate thermal recovery methods. For example, SAGD can offer significantly greater per well production rates, greater reservoir recoveries, reduced water treating costs and dramatic reductions in“Steam to Oil Ratio” (SOR).

The SAGD process is not entirely without drawbacks however; SAGD requires some fresh water and large water re-cycling facilities and large amounts of natural gas to create the steam. Relying upon gravity drainage, SAGD requires comparatively thick and homogeneous reservoirs. Production rates are limited by the relatively high viscosity of bitumen, even hot. Volatile, bitumen-soluble solvents, such as condensable or non-condensable hydrocarbons, can be added to the steam to lower the bitumen viscosity.

Conventional alkaline enhanced oil recovery agents, such as mineral hydroxides (e.g., NaOH, KOH) and carbonates (e.g., NaHCCb, Na2CC>3), can be carried to the oil bearing formation dissolved in any residual hot water in left in the produced steam, but are not volatile enough to be carried by steam alone. In the SAGD process, there is a long and tortuous path through a sand- packed, stream chamber to the water condensation/oil draining front, through which even the smallest water aerosol is unlikely to penetrate.

Certain volatile reagents, such as silanes, organosilicons, and ureas can enhance the recovery of light hydrocarbons by reacting with the surfaces of mineral fines or with the mineral formation itself to decrease the mobility of fines or water or otherwise improve permeability of oil through the formation. With oilsands, however, the surface area of the mineral fines can be so many times greater than that of the bitumen particles that any mineral or formation treating method becomes uneconomical. Moreover, the viscosity of heavy hydrocarbons like bitumen can be so high that the conventional goal of decreasing water mobility and/or increasing oil permeability would actually retard the rate of bitumen production.

Accordingly, improved methods for the recovery of recovering heavy hydrocarbons are needed.

SUMMARY

Provided herein are methods for producing a hydrocarbon from a subterranean formation containing a heavy hydrocarbon. These methods can comprise injecting steam and a volatile cyclic amine into the subterranean formation containing the heavy hydrocarbon. The heavy hydrocarbon can comprise a dense or high viscosity crude oil, bitumen, or a combination thereof. In certain cases, the heavy hydrocarbon can comprise an oil sand.

Injection of the steam and the volatile cyclic amine can produce an oil-in-water emulsion in situ in the subterranean formation. The oil-in-water emulsion can comprise the heavy hydrocarbon, water, an anionic surfactant, and a cosolvent. The volatile cyclic amine is injected in an effective amount to (1) form the anionic surfactant in situ upon contact with the heavy hydrocarbon; and (2) provide excess unreacted volatile cyclic amine that acts as the co-solvent in the oil-in-water emulsion. The oil-in-water emulsion can then be recovered from the subterranean formation, and the oil-in- water emulsion can be separated into its bulk phases (oil and water) to isolate the heavy hydrocarbon.

In some embodiments, the volatile cyclic amine can have an atmospheric pressure boiling point of less than or equal to 105 °C (e.g., less than or equal to 100°C, less than or equal to 95 °C, or less than or equal to 90°C). In some embodiments, the volatile cyclic amine can exhibit a molecular weight of 85.0 g/mol or less (e.g., a molecular weight of 80.0 g/mol or less, or a molecular weight of 75.0 g/mol or less). In some embodiments, the volatile cyclic amine can exhibit a pKa of at least 10.0. In some embodiments, the aqueous phase of the oil-in-water emulsion can have a pH of at least 10.

In certain embodiments, the volatile cyclic amine can be an aliphatic amine (e.g., the volatile amine can be a non-aromatic amine). In certain embodiments, the volatile cyclic amine can not comprise pyrrolidone, pyridine, piperidine, morpholine, pyrrole, cyclohexylamine, or a combination thereof. In particular embodiments, the volatile cyclic amine can comprise pyrrolidine.

The volatile cyclic amine can be added to the steam at a concentration of from 0.5% to 30% by weight based on the total weight of the volatile cyclic amine and steam (e.g., from 0.5% to 20% by weight based on the total weight of the volatile cyclic amine and steam, from 0.5% to 10% by weight based on the total weight of the volatile cyclic amine and steam, or from 0.5% to 5% by weight based on the total weight of the volatile cyclic amine and steam). In some embodiments, the volatile cyclic amine is added to the steam at a concentration of greater than 5% by weight based on the total weight of the volatile cyclic amine and steam (e.g., from 5% to 30% by weight based on the total weight of the volatile cyclic amine and steam, from 5% to 20% by weight based on the total weight of the volatile cyclic amine and steam, or from 5% to 10% by weight based on the total weight of the volatile cyclic amine and steam).

In some embodiments, the steam can further include an additional volatile amine and/or ammonia, a co-solvent, or a combination thereof.

When present, the additional volatile amine can have an atmospheric pressure boiling point of less than or equal to 145° C, such as an atmospheric pressure boiling point of less than or equal to 135° C. In certain cases, the additional volatile amine can have a pK_aof at least 4.95, such as a pK_a of at least 5.0. In some examples, the additional volatile amine can be selected from the group consisting of methyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethyl amine, isopropyl amine, n-propyl amine, diethyl amine, 1,1 -dimethyl hydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine, methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine, ethylenediamine, 3-methoxypropylamine, N,N-diethylhydroxylamine, morpholine, pyrrole, cyclohexylamine and combinations thereof.

When present, the co-solvent can comprise a volatile co-solvent. In some cases, the co solvent can have an atmospheric pressure boiling point of less than or equal to 145° C, such as an atmospheric pressure boiling point of less than or equal to 135° C. In some examples, the co- solvent can be selected from the group consisting of tetrahydrothiophene, tetrahydrofuran, isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec -hexyl alcohol, methanol, and combinations thereof.

DESCRIPTION OF DRAWINGS

Figures 1A-1D show the emulsion phase behavior of 5:5 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 1A; 1,000 ppm, Figure IB; 30,000 ppm, Figure 1C, and 100,000 ppm, Figure ID) at 373 K with varying amounts of pyrrolidine. Single-phase o/w emulsions were observed at 0 ppm. At low salinities (0 and 1,000 ppm), o/w emulsions with excess oil phase were dominant below 20 wt% pyrrolidine concentration. At higher salinities (30,000 and 100,000 ppm), bitumen-rich w/o emulsions were dominant over o/w emulsions. # single-phase oil- in-water emulsion; <¾: oil-in-water emulsions with excess oil phase; 1 : water-in-oil emulsions (bitumen-rich) with oil-in-water emulsions (water-rich); 0: water-in-oil emulsions with excess water phase; A: diluted bitumen.

Figures 2A-2D show the emulsion phase behavior of 7:3 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 2A; 1,000 ppm, Figure 2B; 30,000 ppm, Figure 2C, and 100,000 ppm, Figure 2D) at 373 K with varying amounts of pyrrolidine. At low salinities (0 and 1,000 ppm), single-phase o/w emulsions were observed from 0.5 to 5 wt% pyrrolidine

concentration. O/w emulsions with excess oil phase were dominant below 20 wt% pyrrolidine concentration. At higher salinities (30,000 and 100,000 ppm), bitumen-rich w/o emulsions were dominant over o/w emulsions. single-phase oil-in-water emulsion;€>: oil-in-water emulsions with excess oil phase; l§: water-in-oil emulsions (bitumen-rich) with oil-in-water emulsions (water- rich); S: water-in-oil emulsions with excess water phase; : diluted bitumen.

Figures 3A-3D show the emulsion phase behavior of 9:1 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 3 A; 1,000 ppm, Figure 3B; 30,000 ppm, Figure 3C, and 100,000 ppm, Figure 3D) at 373 K with varying amounts of pyrrolidine. Single-phase o/w emulsions were observed at 1,000 ppm. At low salinities (0 and 1,000 ppm), o/w emulsions with excess oil phase were dominant below 20 wt% pyrrolidine concentration. At higher salinities (30,000 and 100,000 ppm), bitumen-rich w/o emulsions were dominant over o/w emulsions. # single-phase oil-in-water emulsion; ¾?: oil-in-water emulsions with excess oil phase; ϋ: water-in-oil emulsions (bitumen-rich) with oil-in- water emulsions (water-rich); E: water-in-oil emulsions with excess water phase; A diluted bitumen.

Figures 4A-4B show photos of emulsion phase behavior for different pyrrolidine concentrations with 7:3 water-oil-ratio (WOR) at 0 (Figure 4A) and 1,000 ppm (Figure 4B) NaCl at 373 K. From 0.5 to 5 wt% of pyrrolidine, single-phase o/w emulsions were created. At 10 and 20 wt%, o/w emulsions with an excess oil phase were observed. At 30 and 50 wt%, w/o emulsions (bitumen-rich) with o/w emulsion (water-rich) were observed. Note that even a small amount of bitumen in the aqueous phase can make o/w emulsions very dark. Above 70 wt%, bitumen was diluted by pyrrolidine solution. # single-phase oil-in-water emulsion;

oil-in-water emulsions with excess oil phase; il: water-in-oil emulsions (bitumen-rich) with oil-in-water emulsions (water- rich); A: diluted bitumen.

Figures 5A-5C show the emulsion phase behavior at 278 K (Figure 5A), 323 K (Figure 5B), and 353 K (Figure 5C). Salinity and water-oil-ratio were fixed at 1,000 ppm and WOR 7:3. 0.5 wt% pyrrolidine sample created a single-phase o/w emulsion at all temperatures. At pyrrolidine concentrations below 5 wt%, it clearly shows that the vol.% of o/w emulsions became larger with increasing temperature, indicating o/w emulsions turned into a single-phase o/w emulsion. At 373 K, these o/w emulsions became a single-phase as shown in Figure 2B and Figure 4B. # single phase oil-in-water emulsion; %: oil-in-water emulsions with excess oil phase; A: water-in-oil emulsions (bitumen-rich) with oil-in-water emulsions (water-rich); A: diluted bitumen.

Figures 6A-6C plot the viscosity of o/w emulsions (0.5, 2, and 5 wt% pyrrolidine in aqueous phase), w/o emulsions (50 wt% pyrrolidine in aqueous phase), and diluted bitumen (90% pyrrolidine in aqueous phase) at three different temperatures (298 K, 323 K, and 353 K). Salinity and water-oil-ratio were fixed at 1,000 ppm and WOR 7:3. The viscosity of original bitumen (dot line) is also plotted to show the viscosity reduction by creating o/w emulsions.

Figures 7A-7D show the emulsion phase behavior of 5:5 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 7 A; 1,000 ppm, Figure 7B; 30,000 ppm, Figure 7C, and 100,000 ppm, Figure 7D) after aging for three weeks at 373 K with varying amounts of TETA. At 0 ppm, o/w emulsions with excess oil phase were observed at 0.5 wt% and 2.0 wt%. At 1,000 ppm o/w emulsions with excess oil phase were observed at 1.0 wt% and 5.0 wt%. Other than those points, w/o emulsion (bitumen rich) with o/w emulsions (water-rich) were observed at 0 ppm and 1,000 ppm. For 30,000 ppm and 100,000 ppm, all samples showed w/o emulsions with excess water phase. ® : oil-in- water emulsions with excess oil phase; 7; : water-in-oil emulsions (bitumen rich) with oil-in-water emulsions (water rich); : water-in-oil emulsions with excess water phase;

A : diluted bitumen.

Figures 8A-8D show the emulsion phase behavior of 7:3 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 8 A; 1,000 ppm, Figure 8B; 30,000 ppm, Figure 8C, and 100,000 ppm, Figure 8D) after aging for three weeks at 373 K with varying amounts of TETA. Single-phase o/w emulsions were observed up to 5.0 wt% at 0 ppm and 1,000 ppm. At 10 wt%, o/w emulsions with excess oil phase were observed at 0 ppm and 1,000 ppm. From 20 wt%, w/o emulsion (bitumen rich) with o/w emulsions (water-rich) were observed at 0 ppm and 1 ,000 ppm. For 30,000 ppm and 100,000 ppm, all samples showed w/o emulsions with excess water phase. # : a single phase oil-in-water emulsion; ® : oil-in-water emulsions with excess oil phase; il : water-in- oil emulsions (bitumen rich) with oil-in- water emulsions (water rich); C : water- in-oil emulsions with excess water phase; A : diluted bitumen.

Figures 9A-9D show the emulsion phase behavior of 9:1 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 9A; 1,000 ppm, Figure 9B; 30,000 ppm, Figure 9C, and 100,000 ppm, Figure 9D) after aging for three weeks at 373 K with varying amounts of TETA. At 0 ppm, w/o emulsions with excess water phase were observed at 0.5 wt% and 1.0 wt%. At 2.0 wt%, o/w emulsions with excess oil phase were observed. From 5.0 wt%, w/o emulsion (bitumen rich) with o/w emulsions (water-rich) were observed. At 1,000 ppm, o/w emulsions with excess oil phase were observed up to 2.0 wt%. From 5.0 wt%, w/o emulsion (bitumen rich) with o/w emulsions (water-rich) were observed. For 30,000 ppm and 100,000 ppm, all samples showed w/o emulsions with excess water phase. © : oil-in-water emulsions with excess oil phase; L¾ : water-in-oil emulsions (bitumen rich) with oil-in- water emulsions (water rich); E : water- in-oil emulsions with excess water phase; A : diluted bitumen.

Figures 10A-10D show the emulsion phase behavior of 5:5 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 10A; 1,000 ppm, Figure 10B; 30,000 ppm, Figure IOC, and 100,000 ppm, Figure 10D) after aging for three weeks at 373 K with varying amounts of DEA. At 0 ppm and 1,000 ppm, two o/w emulsions (bitumen-rich and water-rich) were observed up to 10 wt%. W/o and o/w emulsions were observed from 20 wt%. Note that this w/o emulsion contained almost all bitumen. For 30,000 ppm samples, a single phase w/o emulsions were observed at low DEA concentration up to 2.0 wt%. Otherwise, w/o emulsions with an excess water-rich phase were observed. For 100,000 ppm samples, w/o emulsions with an excess water-rich phase were observed ϋ : a single phase water-in-oil emulsion; : a single phase diluted bitumen;© : oil-in- water emulsions (bitumen rich) with oil-in- water emulsions (water rich); : water- in-oil emulsions (bitumen rich) with oil-in- water emulsions (water rich); K : water-in-oil emulsions with excess water phase.

Figures 11A-11D show the emulsion phase behavior of 7:3 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 11A; 1,000 ppm, Figure 11B; 30,000 ppm, Figure 11C, and 100,000 ppm, Figure 11D) after aging for three weeks at 373 K with varying amounts of DEA. Single-phase o/w emulsions were observed at low DEA concentrations at salinities 0 ppm and 1,000 ppm. At 0 ppm, o/w emulsion phase with an excess oil phase was observed at 10 wt%. At 1,000 ppm, two o/w (bitumen-rich and water-rich) emulsions were observed up to 10 wt% DEA. Two phase w/o - o/w emulsions were observed from 20 wt% to 70 wt% at both 0 ppm and 1,000 ppm. Note that this w/o emulsion contained almost all bitumen. For 30,000 ppm samples, w/o emulsion with o/w emulsion or excess water-rich phase were observed. For 100,000 ppm samples, w/o emulsions with excess water-rich phase were observed. # : a single phase oil-in-water emulsion;. : a single phase diluted bitumen; : oil-in-water emulsions with excess oil phase; ® : oil-in-water emulsions (bitumen-rich) with oil-in- water emulsions (water-rich); ϋ : water-in-oil emulsions (bitumen-rich) with oil-in- water emulsions (water-rich); i>3 : water-in-oil emulsions with excess water phase.

Figures 12A-12D show the emulsion phase behavior of 9:1 water-oil-ratio (WOR) samples having varying salinities (0 ppm, Figure 12A; 1,000 ppm, Figure 12B; 30,000 ppm, Figure 12C, and 100,000 ppm, Figure 12D) after aging for three weeks at 373 K with varying amounts of DEA. Two phase w/o - o/w emulsions were observed for 0 ppm and 1,000 ppm samples. This w/o emulsion contains almost all bitumen. For 30,000 ppm and 100,000 ppm samples, w/o emulsions with excess water-rich phase were observed. ¾ : water-in-oil emulsions (bitumen rich) with oil-in- water emulsions (water rich); : water- in-oil emulsions with excess water phase.

DETAILED DESCRIPTION

Disclosed are methods for producing a heavy hydrocarbon. As used herein, the terms “heavy hydrocarbons” and "heavy oil" are used interchangeably and generally refer to bitumen, extra heavy oil, heavy oil, or residual hydrocarbons, both natural and pyrogenous.

Industry defines light crude oil as having an API gravity higher than 31.1° and lower than 870 kg/m³ density, medium oil as having an API gravity between 31.1° and 22.3° and having a density between 870 kg/m³ and 920 kg/m³, heavy oil as having an API gravity between 22.3° and 10° and a density between 920 kg/m³ and 1,000 kg/m³, and extra heavy oil as having an API gravity of less than 10° and a density higher than 1,000 kg/m³.

The term "asphaltenes" as used herein refers to hydrocarbons, which are the n-heptane insoluble, toluene soluble component of a carbonaceous material such as crude oil, bitumen or coal. Generally, asphaltenes have a density of from about 0.8 grams per cubic centimeter (g/cc) to about 1.2 g/cc. Asphaltenes are primarily comprised of carbon, hydrogen, nitrogen, oxygen, and sulfur as well as trace vanadium and nickel. The carbon to hydrogen ratio is approximately 1: 1.2, depending on the source.

The term "bitumen" as used herein refers to heavy oil having an API gravity of about 12 or lower. In its natural state as oil sands, bitumen generally includes fine solids such as mineral solids and asphaltenes, but as used herein, bitumen may refer to the natural state or a processed state in which the fine solids have been removed and the bitumen has been treated to a higher API gravity.

In some cases, the heavy hydrocarbon can include, for example, dense or high viscosity crude oils and/or bitumen. In certain examples, the heavy hydrocarbon can comprise Athabasca bitumen.

Heavy hydrocarbons can be difficult to produce. These hydrocarbons are very viscous and often cannot be produced using oil wells that are powered only by formation pressures. One method of lowering the viscosity of heavy hydrocarbons in subterranean formations is to flood the formation with steam. Steam increases the temperature of the hydrocarbons in the formation, which lowers their viscosity, allowing them to drain or be swept towards an oil well and be produced. Steam can also condense into water, which can then act as a low viscosity carrier phase for an emulsion of oil, thereby allowing heavy hydrocarbons to be more easily produced.

In some embodiments, methods of recovering heavy hydrocarbons can employ an oil well. In these embodiments, the hydrocarbon in a subterranean formation can be contacted with an admixture of steam and a volatile cyclic amine or an admixture of a volatile cyclic amine with a volatile amine and/or ammonia. The steam, volatile cyclic amine, or the volatile cyclic amine admixture can be introduced downhole using either the same well used for production or other wells used to introduce the steam into the formation. Either way, the steam condenses and forms an aqueous phase which can help liberate the heavy hydrocarbon from the mineral and carry it towards the production well.

In another embodiment, methods of recovering heavy hydrocarbons, especially bitumen, can include recovering heavy hydrocarbons from a hydrocarbon bearing ore. Examples of such ores include bitumen-rich ores commonly known as oil sand(s) or tar sand(s).

Enormous hydrocarbon reserves exist in the form of oil sands. The asphalt-like glassy bitumen found therein is often more difficult to produce than more liquid forms of underground hydrocarbons. Oil sand bitumen does not flow out of the ground in primary production. Such ore can be mined in open pits, the bitumen separated from the mineral ex situ using at least warm water, sometimes heated with steam, in giant vessels on the surface. Alternatively, the ore can be heated with steam in situ, and the bitumen separated from the formation matrix while still underground with the water condensed from the steam.

Unlike conventional heavy crude oils, the bitumen in oil sands is not continuous but in discrete bits intimately mixed with silt or capsules encasing individual grains of water wet sand. These bituminous hydrocarbons are considerably more viscous than even conventional heavy crude oils and there is typically even less of it in the formation-even rich oil sand ores bear only 10 to 15% hydrocarbon.

One method of recovering such bitumen is to clear the earthen overburden, scoop up the ore from the open pit mine, and then use heated water to wash away the sand and silt ex situ, in a series of arduous separation steps.

A more recent process separates the hydrocarbons from the sand in situ using horizontal well pairs drilled into the deeper oil sand formations. High pressure, dry steam (e.g., 500°C) is injected into an upper (injector) well, which extends lengthwise through the upper part of the oil sand deposit. The steam condenses, releasing its latent and sensible heat which melts and fluidizes the bitumen near the injector well. As the oil and water, now at about 130°C to about 230°C, drains, a dry steam chamber forms above the drainage zone.

One disadvantage to this method of hydrocarbon production is that new steam, along with any additives that it may include, may have to travel ever longer distances through this porous sand and clay to reach the progressing interface between the dry steam chamber and the zone where the oil and water drainage commences (a production front). This process is known as steam assisted gravity drainage and is commonly referred to by its acronym,“SAGD.”

Unlike a conventional steam drive, the pressure of the steam is not primarily used to push the oil to the producer well; rather, the latent heat of the steam is used to reduce the viscosity of the bitumen so that it drains, along with the water condensed from the steam, to the lower, producer well by gravity. Since, at the production temperature of about 150°C, pure water is about 300 times less viscous than pure bitumen, and the typically water-wet formation can't hydrophobically impede the flow of water, the water drains much faster through the formation than the melted bitumen.

Moreover, water-based (oil-in-water) emulsions flow mostly like water— they are not much more viscous than water itself. This is believed to be because the charge stabilized, oil-in- water particles are electrostatically repelled and resist rubbing against each other. Water droplets in oil, in contrast, are sterically stabilized and flow past each other only with increased friction. The result is that concentrated emulsions of water in oil can be several times more viscous than the pure oil itself. Thus, overall, a water-based emulsion can flow as much as a thousand times faster than its oil-based counterpart, and so typically produce far more oil, even when it carries a lower fraction of oil.

In a typical SAGD start-up, water is the first thing out of the ground. The concentration of hydrocarbon in the production fluid increases with time until eventually the oil concentration levels out at about 25 to 35 percent of the produced fluid. Thus, the limiting“steam to oil ratio” or SOR is about 2 to 3. Whatever the condition of the fluids underground, what reaches the first phase separator on the surface may not be two bulk phases, that is, an oil-based emulsion and a water-based emulsion. Instead, the predominant emulsion is usually oil-in- water. This emulsion typically carries with it is the most bitumen it can carry without flipping states, or inverting, into a water-in-oil emulsion.

In practice then, the SOR, and thus the oil production rate, may be more limited by the fluid flux— the transfer of motion to the oil via the water flow— than the thermal flux— the transfer of heat to the oil via steam. Increasing the fraction of oil carried by the water, then, produces more oil for same steam, and is thus highly desirable.

The use of a volatile cyclic amine can increase both the efficiency and the effectiveness with which heavy hydrocarbons are dispersed into (and thus carried by) water. Increased efficiency results in lower steam requirements, which results in lower energy costs. In some fields, heavy crude oil is recovered at a cost of ½ of the oil produced being used to generate steam. It would be desirable in the art to lower steam requirements thereby lowering the use of recovered

hydrocarbons or purchased energy in the form of natural gas for producing heavy hydrocarbons. Increased effectiveness results in greater total recovery of bitumen from the formation. Less oil is left wasted in the ground. This increases the return for the fixed capital invested to produce it.

Another method of recovery of heavy hydrocarbons employs volatile hydrocarbon vapors to enhance the extraction. This“vapor extraction” method is commonly known in the art as VapEx. In this method, dilution with light hydrocarbon rather than heating with steam is used to reduce the viscosity of the heavy hydrocarbons. These methods are known in the art and may be found in U.S. Pat. No. 4,450,913 to Allen et al, and U.S. Pat. No. 4,513,819 to Islip et al, U.S. Pat. No. 5,407,009 to Butler et al, U.S. Pat. No. 5,607,016 to Butler, U.S. Pat. No. 5,899,274 to Frauenfeld et al, U.S. Pat. No. 6,318,464 to Mokrys, U.S. Pat. No. 6,769,486 to Lim et al, and U.S. Pat. No. 6,883,607 to Nenniger et al., which are incorporated herein in their entirety by reference.

As in the case with steam alone, however, merely reducing the viscosity of the heavy hydrocarbon generally will not move the oil as quickly as dispersing it into a much thinner, aqueous phase. The heavier the hydrocarbon the more this is true. In formations containing some water, the methods described herein may be used with solvent injection subject to the caveat that there is sufficient water in the formation to allow the volatile cyclic amine to create a water-based, oil bearing fluid to increase the efficiency and/or the effectiveness of the subject process compared to the same process practiced without the volatile cyclic amine.

Where formation water is insufficient to allow the volatile cyclic amine to create a water- based, oil-bearing fluid, combinations of volatile hydrocarbon diluents and steam can be used with the methods described herein. One combination process is commonly known as Light Alkane Steam Enhanced Recovery, or“LASER”. The addition of steam and diluent provides an aqueous carrier phase and lowers the viscous impediment to the heavy oil dispersing into it. The methods described herein can amplifies this effect by increasing the forces driving the oil into the water and keeping it there. This allows the water to carry more oil, reducing the demand for steam and the energy needed to generate it.

In the practice of the methods described herein, a volatile cyclic amine can be used to enhance heavy hydrocarbon production. In some embodiments, the volatile cyclic amine can have an atmospheric pressure boiling point of less than or equal to 105°C (e.g., less than or equal to 100°C, less than or equal to 95°C, or less than or equal to 90°C). In some embodiments, the volatile cyclic amine can exhibit a molecular weight of 85.0 g/mol or less (e.g., a molecular weight of 80.0 g/mol or less, or a molecular weight of 75.0 g/mol or less). In some embodiments, the volatile cyclic amine can exhibit a pKa of at least 10.0. In some embodiments, the aqueous phase of the oil-in- water emulsion can have a pH of at least 10.

While not wishing to be bound by any theory, it is believed that anionic surfactants can be created in situ during practice of the methods described herein from compounds with amine- reactive functional groups commonly found in heavy hydrocarbons. In particular, the long chain carboxylic acids generally referred to as naphthenic acids react on contact with basic volatile cyclic amines form oil-emulsifying soaps. Thus, the cyclic amine can be selected so as to possess both (1) a pK_a value high enough to react with active compounds in the heavy hydrocarbons to produce anionic surfactants in si nr, and (2) volatile enough to be readily transported to the reactive sites.

In some embodiments, the volatile cyclic amines can have a volatility that is sufficient to allow for their delivery to the production front though a depleted formation with dry steam. For example, the surfactants formed in situ by such a delivery may accelerate the release (or inhibit the adsorption) of bitumen encapsulating sand grains in oil sands. This release may generate stable, low viscosity, bitumen-in- water dispersions or emulsions that flow more swiftly through a water- wet sandpack. Thus, this more oil laden water accelerates the recovery of bitumen from oilsands.

In such an embodiment, the condensed water is also able to carry a higher loading of this surface-activated bitumen than non-activated bitumen. Higher carrying capacity reduces the water and thus the steam and thus the natural gas (or other energy source) needed to produce a barrel of bitumen. In such a business model, capital costs may be more quickly recovered, and operating costs are permanently reduced, all of which are clearly desirable in a commercial operation.

The cyclic amine compounds added to steam may be sufficiently volatile to be transported by the steam in the vapor phase such that it can penetrate the formation to the bitumen draining front or production front where the steam is condensing. In practice, this means that the amines boil below or not too much above the temperature of water at equal pressure. Provided the amine is sufficiently alkaline, it cannot be too volatile, since it will react with the bitumen from gas phase. Even low boiling gasses, such as ammonia, can react with bitumen on contact, increasing the bitumen's water dispersibility.

As already stated, it is desirable for the amines to be sufficiently alkaline to react with naphthenic (carboxylic) acids in the heavy hydrocarbons to form carboxylate anions which are effective soaps. Carboxylic acids, as a class, have a pK_a of from about 3.7 to about 4.9. Therefore, the cyclic amine should be a strong enough base to react with some common carboxylates (thereby forming surfactants). The soaps so formed in situ may, for example, enhance the release of bitumen from an oil sand and suspend the bitumen in the water condensed from the steam. The water thereby transports more bitumen to the surface.

The cyclic amine can be injected in an effective amount to (1) form the anionic surfactant in situ upon contact with the heavy hydrocarbon; and (2) provide excess unreacted cyclic amine. The excess unreacted cyclic amine can act as a co-solvent which reduces the viscosity of the hydrocarbon phase in the oil-in-water emulsion.

Some hydrocarbon recovery methods employ caustic and/or carbonates as a source of base for their applications. The use of caustic and/or carbonates is not always desirable because of problems associated with the accumulation of alkali metals in the hydrocarbons being produced. In the methods described herein, the cyclic amines may be used to replace this function, thereby overcoming the accumulation of sodium or other alkali metals in produced hydrocarbons or the recycled production water. In certain embodiments, the compositions injected herein can be free of inorganic alkali agents such as sodium carbonate.

Once hydrocarbons are produced using the methods described herein, they may be recovered from the resultant hydrocarbon in water emulsion using any method known to be useful to those of ordinary skill in the art. For example, the emulsion may be broken using polyamine, polyether, metal hydrate, or acid-based emulsion breakers or“reverse” breakers ahead of the various separation vessels.

The cyclic amines may be added to the steam and, optionally, solvent in any way known to be useful to those of ordinary skill in the art. They may be admixed in advance and injected as a single phase or mixture. They may also be co-injected. They may be used in any concentration that is useful, useful being defined as being more effective or efficient than a when an otherwise identical hydrocarbon recovery process is practiced in the absence of the cyclic amine (or with diethylamine).

In some embodiments, the volatile cyclic amine can be added to the steam at a

concentration of from 0.5% to 30% by weight based on the total weight of the volatile cyclic amine and steam (e.g., from 0.5% to 20% by weight based on the total weight of the volatile cyclic amine and steam, from 0.5% to 10% by weight based on the total weight of the volatile cyclic amine and steam, or from 0.5% to 5% by weight based on the total weight of the volatile cyclic amine and steam). In some embodiments, the volatile cyclic amine is added to the steam at a concentration of greater than 5% by weight based on the total weight of the volatile cyclic amine and steam (e.g., from 5% to 30% by weight based on the total weight of the volatile cyclic amine and steam, from 5% to 20% by weight based on the total weight of the volatile cyclic amine and steam, or from 5% to 10% by weight based on the total weight of the volatile cyclic amine and steam).

The hydrophilic-lipophilic balance (HLB) of the surfactants created in situ may be optimized for maximum utility on different bitumens by manipulating the structure of the cyclic amine. Oil affinity (lipophilicity) of the surfactant may be increased by increasing the number or size of hydrocarbon groups on the cyclic amine. Decreasing the number or size of hydrocarbon groups will decrease its oil affinity and increase its water affinity (hydrophilicity).

The methods described herein may be practiced in the absence of other reagents, reactants, or surfactants that may be introduced from the surface. For example, the methods described herein may be practiced in the absence of materials used to modify the surface wettability or other property of the mineral in the formation, for example, to decrease the mineral's mobility or the fluid permeability though it. In particular, mineral hydrophobizing reactants such as silanes and similar silicon-based compounds and water shut off agents such as water-soluble polymers or their precursors are to be avoided as detrimental to the enhanced flow of water promoted by the methods described herein. More broadly, any additive preferentially reacting with or adsorbing onto minerals surfaces is to be avoided where the mineral surface area, for example, in oilsands with clay fines, is so many times larger than the surface area of any oil-water emulsion that it's would be grossly uneconomical.

In other embodiments, the steam can further include an additional volatile amine and/or ammonia, a co-solvent, or a combination thereof.

When present, the co-solvent can comprise a volatile co-solvent. In some cases, the co solvent can have an atmospheric pressure boiling point of less than or equal to 145° C, such as an atmospheric pressure boiling point of less than or equal to 135° C. The co-solvent can be, for example, an alcohol, an aldehyde, a ketone, an ether, an ester, an amide, a hydrocarbon, or a combination thereof. In certain embodiments, the co-solvent can possess six or fewer carbon atoms. In some examples, the co-solvent can be selected from the group consisting of

tetrahydrothiophene, tetrahydrofuran, isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol, methanol, and combinations thereof.

The term“steam,” as used herein, has its ordinary meaning of water vapor heated to or above the boiling point. In the art of recovering hydrocarbons from oil sands, steam is sometimes further qualified as“low quality steam” and“high quality steam.” For the purposes of this application, the term“high quality steam means steam that, at the point of injection into oilsands, has at least 70% of the water in this fluid stream in the form of steam and 30% or less in the form of condensed water. In some embodiments, it is necessary that that at least 80% by weight of the water be in the form of water vapor. Any fluid stream having less than 70% water vapor is low quality steam.

By way of non-limiting illustration, examples of certain embodiments of the present disclosure are given below.

EXAMPLES

Example 1: Oil-in-Water (O/W) Emulsification of Athabasca Bitumen with Pyrrolidine Solution.

This example describes the use of pyrrolidine solutions to induce the oil-in- water (o/w) emulsion of Athabasca bitumen without using a synthetic surfactant. Pyrrolidine, an organic alkali, acts not only as an alkali that generates natural surfactants from acidic oil components in bitumen, but also as a cosolvent that improves the fluidity of the o/w emulsions. Experimental results show that the o/w emulsions created by pyrrolidine solutions can result in a large mobility increase of bitumen because of their low viscosity and high bitumen content. Oil-in-water emulsions were observed at low pyrrolidine concentrations (below 20 wt% and as low as 0.5 wt%) and low salinities (0 and 1,000 ppm). For example, the sample of 0.5 wt% pyrrolidine in 1000-ppm NaCl brine with 7:3 water-oil-ratio showed a single-phase o/w emulsion at temperatures of from 298 K to 373 K. In comparison to the original bitumen, the o/w emulsion was 4 to 6 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.

The affinity of the organic alkali for asphaltic bitumen is important for o/w emulsification at a wide range of temperatures. Pyrrolidine was found to be superior to other organic alkalis tested (e.g., diethylamine and triethylenetetramine), likely because the cyclic structure makes pyrrolidine more compatible with the asphaltic bitumen. The favorable result with pyrrolidine is also confirmed by the Hansen solubility dispersion parameter.

Background

Bitumen is highly viscous because of its asphaltene content (e.g., 20 wt% n-pentane insoluble), and it is often immobile at reservoir conditions. Steam injection is widely used to recover bitumen, in which the latent heat injected can effectively mobilize the bitumen near thermal fronts. However, steam injection methods, such as cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD), are energy-intensive, and their efficiency is highly sensitive to reservoir properties, such as heterogeneous permeability, porosity, thickness, and phase saturations.

To improve the efficiency of these steam injection methods, solvent-steam co-injection has been tested at lab and field scales. Solvent-steam co-injection aims to recover bitumen more efficiently by using the heating and dilution mechanisms together. These studies focused mainly on hydrocarbon solvents, such as propane, butane, and diluent, which is a mixture of pentane and heavier hydrocarbons. Dimethyl ether (DME) was recently investigated as a potential additive to steam. Unlike hydrocarbon solvents, it is soluble in both oil and water. It was shown that the solubility of DME in oil and water can yield unique mechanisms of bitumen recovery through reducing steam-oil ratio (SOR) and increasing solvent recovery.

If it is properly implemented, solvent-steam co-injection yields a reduction of SOR in comparison to the conventional steam injection methods. However, the presence of condensed water near the thermal fronts can adversely affect the oil mobility along the edge of a steam chamber. One drawback of steam injection processes is that water throughput is inherently large. However, bitumen can in principle be efficiently transported in the form of o/w emulsion if the emulsion is rich in bitumen and much less viscous than the original bitumen. Methods of emulsifying heavy oil have been investigated for a variety of different purposes. For example, alkali injection for heavy oil recovery has been studied in water flooding processes, such as alkaline- surfactant, alkaline- surfactant-polymer, and alkaline-cosolvent-polymer flooding. Alkalis in these processes form natural surfactants by reaction with acidic oil components.

Different combinations of alkalis, salts, surfactants, co-solvents, and polymers can be used to achieve ultra- low interfacial tension. For pipeline transportation of heavy oil, o/w emulsion viscosity has been studied with different surfactants, alkalis, and solvents at different water-oil- ratios (WORs) and shear rates.

Synthetic surfactants can be used as steam additives for SAGD and CSS. For example, commercially available hydrophilic viscosity reducers, hydrophilic surfactants, and thin film spreading agents can be used to form o/w emulsions or to demulsify water-in-oil (w/o) emulsion to enhance in situ bitumen transport. The potential mechanisms for lowering SOR by injecting these surfactants with steam include the wettability alteration from oil-wetting to more water-wetting, and reduction of interfacial tension.

As for use of alkalis with no synthetic surfactants, sodium carbonate can be used for bitumen emulsification by natural surfactants. Sodium carbonate can activate natural surfactants and form o/w emulsions from Iranian heavy crude oil and Cerro Negro bitumen. In both cases, o/w emulsions are observed at the sodium carbonate concentration ranges of from 2,000 to 10,000 ppm. However, sodium carbonate cannot be transported as part of the vapor in steam-injection processes, such as SAGD.

In contrast to other studies of heavy oil emulsification, this example focuses on bitumen-in- water emulsification by using an organic alkali without using additional surfactants or cosolvents. Organic alkali can act as alkali and cosolvent, and use of a single component with multiple functions can yield a simpler solution to enhancement of bitumen transport. To this end, it is important to find an optimal organic alkali that can form the o/w emulsion that is much less viscous than the original bitumen, yet has a high concentration of bitumen.

Bitumen is a complex mixture of hydrocarbons and typically contains asphaltenes and resins at high concentrations. It has been found that asphaltenes and resins in bitumen interact with water and play an important role in creating stable emulsions. In addition, the ratio between asphaltenes and resins is also the important factor in the creation of emulsions.

It is of fundamental importance to study the phase behavior and rheology of emulsions created by bitumen and organic alkali solution, prior to validation by a coreflooding experiment or a field test. Diethylamine (DEA) and triethylenetetramine (TETA) have been evaluated for bitumen emulsification. Aqueous solutions of these organic alkalis created single-phase o/w emulsions of low viscosity with Athabasca bitumen. It is believed that the chemical structure of the organic alkali influences the resulting emulsion phase behavior and rheology as it is acting as cosolvent in these mixtures.

Therefore, this example investigates an organic alkali which contains a cyclic structure. Pyrrolidine was chosen among cyclic amines because its volatility (vapor pressure) is similar to n- C6 and n-C7.

In this example, we (1) determine whether o/w emulsions can be formed by adding pyrrolidine to Athabasca bitumen and NaCl brine; (2) establish phase behavior data for bitumen emulsification at different pyrrolidine concentrations, WORs, brine salinities, and temperatures; (3) measure the oil content and viscosity of o/w emulsions to evaluate the effectiveness of the o/w emulsion as a bitumen carrier; and (4) compare three organic alkalis, DEA, TETA, and pyrrolidine, in terms of bitumen emulsification.

Materials and Experimental Procedure

Bitumen. Dehydrated Athabasca bitumen was used in this example. The molecular weight (MW) of the bitumen sample was 532 g/mol. The density was 0.985 g/ml at 335 K and atmospheric pressure. The SARA composition was 24.5 wt% saturates, 36.6 wt% aromatics, 21.1 wt% resins, and 17.8 wt% asphaltenes (pentane insoluble). Detailed data of viscosity and density for this bitumen sample can be found in Baek et al.“Comparative Study of Oil-Dilution Capability of Dimethyl Ether and Hexane as Steam Additives for Steam- Assisted Gravity Drainage.” SPE Reservoir Evaluation & Engineering 2018 (https://doi.org/10.2118/187182-PA).

The total acid number (TAN) was 3.56 mg-KOH/g-oil. The acid number of oil can be an important factor for alkali-based oil recovery methods. Generally speaking, acid numbers of at least 1.5 mg-KOH/g-oil are needed to support alkali-based oil recovery methods. In sandpack flooding experiments with four oil samples with acid numbers between 1.85 and 4.66 mg-KOH/g-oil, higher oil recovery was observed when the oil had a higher acid number. The acid number of the bitumen sample in this example (3.56 mg-KOH/g-oil) suggests that Athabasca bitumen contains a sufficient quantity of acidic components to create natural surfactants by reaction with an alkali.

Organic Alkali. In this example, pyrrolidine (C₄H₉N) was studied for o/w emulsification of an Athabasca bitumen sample. These results were then compares to the oil-in-water

emulsification of bitumen using dimethylamine (DEA: C₄H₁₁N) and triethylenetetramine (TETA: C6H18N4). DEA, TETA, and pyrrolidine are all organic alkalis; however, they possess significantly different chemical structures. Unlike DEA and TETA, pyrrolidine contains a cyclic structure. Pyrrolidine’s molecular weight and normal boiling temperature are 71 g/mol and 360 K, respectively. The pyrrolidine used in this example had a purity higher than 99.5%. Generally, a high pH is needed to form natural surfactants from the acidic components in bitumen. As shown in Table 1, pyrrolidine can create a high pH aqueous phase when dissolved into the aqueous phase. For example, the pH of aqueous solutions containing varying quantities of pyrrolidine ranged between 10.6 and 11.7 when it was mixed with 1,000 ppm NaCl brine.

Table 1. pH of pyrrolidine solutions containing varying concentrations of pyrrolidine at room temperature.

Brine. Analysis of the produced water from the production wells, from which the bitumen sample was taken, showed that the produced water only contained a few hundreds of ppm of NaCl. Therefore, NaCl was used as the only salt in the brines tested in this example. Although the actual salinity is low in the produced water, different NaCl concentrations were prepared with deionized water for this example, ranging from 0 to 100,000 ppm.

Emulsion Phase Behavior. Samples were prepared at 10 different pyrrolidine

concentrations (0.5, 1, 2, 5, 10, 20, 30, 50, 70, and 90 wt% in aqueous phase) with 4 different salinities (0, 1,000, 30,000, and 100,000 ppm) for 3 different WORs (5:5, 7:3, and 9:1). Because of NaCl’s solubility limit in water, the maximum salinity tested is 30,000 ppm for 90 wt% pyrrolidine, and 100,000 ppm for 70 wt% pyrrolidine. As a result, emulsion phase behavior was studied for 111 samples at 373 K.

For each test, 4 ml sample was prepared in a 10 ml Pyrex pipette as described below. First, the tip of a pipette was sealed by flame. Then, the aqueous phase was added in the pipette with specified amounts of brine and pyrrolidine. A WOR was set by adding heated bitumen (at 353 K) to the aqueous phase in the pipette. Once all components were added, argon gas was injected into the pipette as blanket gas. Finally, the neck of the pipette was sealed by flame. The samples were aged in an oven at 373 K for 3 weeks. During the aging period, all samples were mixed 4 times a day. Then, the samples were rested for 2 days before emulsion phase behavior was recorded at 373 K.

The pH values measured for the aqueous phase after mixing indicated that all acidic components in bitumen had reacted with pyrrolidine. The minimum pH value was measured to be 9.8 for the sample of 0.5 wt% pyrrolidine with WOR 5:5.

Emulsion types (water-external and oil-external) were identified with several different methods: visual observation, emulsion volume, emulsion fluidity in a pipette, and the method described in Kumar, R, et al.“Heavy-Oil Recovery by In-Situ Emulsion Formation.” SPE Journal 2012;17(2): 326-334 (https://doi.org/10.2118/129914-PA). Briefly, emulsion types were assessed by placing emulsion droplets into deionized water and toluene. Oil-in-water emulsion droplets spread in deionized water, but not in toluene. The opposite behavior was observed for w/o emulsions.

Viscosity and Bitumen Content in Emulsion. After the general emulsion phase behavior scans, the viscosity and bitumen content in emulsions were measured for selected samples: 5 pyrrolidine concentrations (0.5, 2, 5, 50, and 90 wt% in aqueous phase) at 1,000 ppm and WOR 7:3. The salinity and WOR were selected by considering typical operating conditions in the oil field from which the bitumen sample was taken for this research.

For this more detailed analysis of specific emulsion samples, 8 ml of the sample was prepared in a 10 ml Pyrex pipette using the same preparation procedure of emulsion phase behavior. Phase behavior of these samples was observed at 4 different temperatures (298 K, 323 K, 353 K, and 373 K) and 3 different aging times (1 week, 2 weeks, and 3 weeks).

The viscosity of emulsion phase was measured by a rheometer (Model: ARES LS-1 from TA Instruments) with 50 mm diameter parallel bottom and upper plates at 3 different temperatures (298 K, 323 K, and 353 K). Viscosity measurement temperature was limited by pyrrolidine’s normal boiling temperature (360 K). For each viscosity measurement, an emulsion sample taken from a pipette was transferred on the bottom parallel plate of the rheometer. Different gap sizes were applied for different viscosity ranges by considering the maximum torque of this rheometer. The gap size was set to 0.4 mm for o/w emulsions, and 0.8 mm for w/o emulsions. The range of shear rates was from 0.1 to 100 sec-1. The lower limit of torque during viscosity measurement was set to 0.74 pNm because measurements at lower torques might be unreliable. For each emulsion sample, an average viscosity was reported based on 2 - 4 times of repeated measurements.

Special care was taken to avoid any possible errors in the viscosity measurement using this particular rheometer. For each measurement, a new sample was used to prevent any alteration of emulsion rheology through experiencing high shear rates. Although it is ideal to measure viscosity right after the loading of a sample, samples were placed on the rheometer for several minutes for viscosity measurements at 323 K and 353 K to reach the target temperature.

The amount of bitumen in o/w emulsions was measured by separating bitumen from water by adding HC1 for demulsification. For 1 ml of o/w emulsion, 2 ml of 3.5 molarity HC1 solution was added to make a total solution of 3 ml. This mixture of emulsion and HC1 was stirred until transparent water was separated from bitumen along with the protonated alkali. Then, the volume of bitumen was obtained by measuring the volume of separated water. The material balance for the entire sample (2.4 ml of bitumen in the total sample of 8 ml) was confirmed for the determination of the bitumen amount in o/w emulsions. For w/o emulsions, the bitumen content in emulsion was not measured since bitumen was existing only in the emulsion phase.

Results

Emulsion Phase Behavior. Results of the emulsion phase behavior for 111 samples at 373 K are summarized in Figures 1A-1D, Figures 2A-2D, and Figures 3A-3D. In these figures, phase types were identified based on the method described above. The observed phase behavior can be categorized into 5 types: 2 types for a single-phase and 3 types for two phases. The single-phase types are“o/w emulsion” and“diluted bitumen”. The two- phase types are“o/w emulsion with an excess-oil phase”,“w/o emulsion with an excess-water phase”, and“bitumen-rich w/o emulsion with water-rich o/w emulsion”. Table 2 presents the transition of bitumen-rich phase between o/w and w/o to clarify favorable conditions for o/w emulsification. It shows that o/w emulsion is dominant at low salinities (0 ppm and 1,000 ppm) and low alkali concentrations (below 20 wt%). As an example, photos of emulsion samples with WOR 7:3 at 0 and 1,000 ppm are presented in Figures 4A-4B. Figures 5A-5C show the phase behavior of samples with 1,000 ppm NaCl and WOR 7:3 at 298 K, 323 K, and 353 K. These figures can be compared with Figures 2B and 4B (at 373 K).

Table 2. Bitumen-rich emulsion types with respect to alkali concentration, WOR, and salinity based on 111 samples at 373 K. This table clearly shows that o/w emulsion is dominant at low salinities (0 and 1,000 ppm) and low alkali concentrations (lower than 20 wt%).

Salinity 1,000 ppm

WOR Pyrrolidine Concentration [wt%]

0.5 1 2 5 10 20 30 50 70 90

5:5 o/w o/w o/w o/w o/w o/w w/o w/o w/o dilution

7:3 o/w o/w o/w o/w o/w o/w w/o w/o dilution dilution 9:1 o/w o/w o/w o/w o/w o/w w/o w/o w/o dilution

Observations based on these figures are explained below. First, o/w emulsions were dominant at low salinity (0 and 1,000 ppm) while w/o emulsions were dominant at high salinity (30,000 and 100,000 ppm). With increasing salinity, the interaction between water molecules and salt ions increases compared to that between water molecules and surfactants. As a result, the interfacial tension (IFT) between emulsion and oil decreases whereas the IFT between emulsion and water increases with increasing salinity.

Second, o/w emulsions were dominant at low pyrrolidine concentrations, and w/o emulsion appeared with increasing pyrrolidine concentration. At the pyrrolidine concentration of 90 wt%, single-phase bitumen was highly mobile, indicating a solvent-diluted bitumen phase. The addition of water-soluble organic liquids can invert o/w emulsions to w/o emulsions. Indeed, the inversion from o/w to w/o emulsion was observed with increasing pyrrolidine concentration. The pH values of o/w emulsion samples with 0.5, 2, and 5 wt% pyrrolidine at WOR 7:3 were greater than 10 at room temperature (Figure 5A). This indicates that acidic components were reacted with pyrrolidine and therefore, the amounts of natural surfactants were similar for the o/w emulsion samples. That is, it is conceivable that the effect of pyrrolidine on emulsion phase behavior came from the excess amount of pyrrolidine as cosolvent, rather than the concentration of natural surfactants. 0.5 wt% pyrrolidine was improved in comparison to 2 wt% and 5 wt%; the excess pyrrolidine worked as cosolvent more effectively at 5 wt% than at 2 wt%. The latter observation may come from the dilution of bitumen that was more significant for the 5 wt% pyrrolidine sample. Third, with increasing WOR, o/w emulsions became lean in bitumen owing to a smaller amount of natural surfactants. The effect of WOR on emulsion phase behavior depends on properties of oil and therefore, the type of natural surfactants activated by alkalis.

Figures 5A-5C show that higher temperature was more favorable for creating a single-phase o/w emulsion. The effect of temperature on emulsion phase behavior may be explained through the temperature effect on the IFT between oil and aqueous solution. However, the uncertainty in natural surfactant properties makes it difficult to give a systematic explanation of the temperature effect on phase behavior in this example.

At a given surfactant concentration, the IFT can either decrease or increase with increasing temperature depending on the salinity. At a given salinity, it was observed that IFT decreased up to a certain temperature and increased at higher temperatures. The IFT reduction between bitumen and surfactant solution with increasing temperature has been measured. In these cases, the IFT between bitumen and surfactant solution was decreased from 323 to 373 K at the NaCl salinity range between 0 and 2,500 ppm. Natural surfactants in this example may have given a similar trend, in which the natural surfactants at 1,000-ppm NaCl brine decreased the IFT between bitumen and aqueous phase as temperature increased from 298 K to 373 K.

In summary, a range for o/w emulsification was found at small concentrations of pyrrolidine at salinities below 1 ,000 ppm. For example, desirable emulsification of bitumen in water as a single phase was observed at the following conditions: (1) for WOR 9:1, 1 to 5 wt% pyrrolidine at 1,000 ppm, (2) for WOR 7:3, 0.5 to 5 wt% pyrrolidine at 0 and 1,000 ppm, and (3) for WOR 5:5, 1 to 10 wt% pyrrolidine at 0 ppm.

Bitumen Content and Viscosity of Emulsions. The result of bitumen contents in o/w emulsions and viscosities of emulsions for selected samples are described. The samples studies were performed at 5 pyrrolidine concentrations (0.5, 2, 5, 50, and 90 wt%) at WOR of 7:3 and 1,000 ppm salinity at 3 different temperatures (298 K, 323 K, and 353 K) as explained above. The phase behavior for these samples were previously given in Figures 5A-5C.

Table 3 presents the bitumen contents in o/w emulsions at different temperatures.

Measurement of the bitumen content in emulsion for samples with shorter periods of aging, 1 week and 2 weeks, showed that the bitumen content was steady after 1 week. Figures 2B and 5A-5C showed that a single-phase o/w emulsion was created with 0.5 wt% pyrrolidine sample for all temperatures. These emulsion samples have the maximum bitumen content, 2.4 ml, which is 30% of the entire emulsion volume. Table 3. The amount of bitumen in o/w emulsions at 1,000 ppm and 7:3 WOR at varying temperatures. The amount of bitumen is 2.4 ml in the total of 8 ml of each sample. Samples with 0.5 wt% pyrrolidine created a single-phase o/w emulsion at all temperatures. As temperature increases, bitumen content in emulsion also increases for a given o/w emulsion. Refer to Figures

5A-5C for the corresponding phase behavior.

Temperature 298 K

Temperature 323 K

Temperature 353 K

As shown in Figures 5A-5C, the amount of the excess oil phase for these pyrrolidine concentrations of 2 wt% and 5 wt% decreases with increasing temperature. At 373 K, the excess oil phase was not observed as the bitumen was completely emulsified in water as shown in Figure 2B and Figure 4B.

Results of the viscosity measurement are presented in Table 4 and Figures 6A-6C. Shear thinning behavior was observed for all fluids studied, except for the original bitumen. The shear thinning behavior indicates hydrodynamic interaction and deformation of dispersed droplets.

However, the w/o emulsion at 50 wt% pyrrolidine concentration was only weakly shear-thinning likely because there was only a small amount of dispersed water in this oil-external emulsion. The bitumen content and temperature affect the viscosity of o/w emulsions in a complex manner. With increasing temperature, the bitumen content tends to increase in the o/w emulsion, but the viscosity of bitumen itself decreases. The effect of temperature on o/w emulsion viscosity can be observed for the case of 0.5 wt% pyrrolidine; i.e., the viscosities of the single-phase o/w emulsion with 0.5 wt% pyrrolidine at 298 K were similar to those at 323 K. At 353 K, however, the o/w emulsion became much less viscous especially at lower shear rates. The effect of an increased oil content in o/w emulsion can be observed for the viscosity data obtained for 2 wt% pyrrolidine samples at 298 K and 323 K, where the o/w emulsion viscosity increases with increasing temperature. The data for 5 wt% pyrrolidine samples at the three temperatures in Table 4 show that the viscosity of o/w emulsion decreased with increasing temperature in spite of the increased oil content at 353 K.

Table 4. Emulsion viscosity (WOR 7:3, Salinity 1,000 ppm). (*) Measurement was impossible due to the torque limit of the rheometer.

Temperature 298 K

Temperature 323 K

Temperature 353 K

Water-in-oil emulsions created with 50 wt% pyrrolidine were more viscous than o/w emulsions created with lower pyrrolidine concentrations. The effect of temperature on viscosity reduction is more prominent for w/o emulsions as the external phase is oil. At the shear rate of 1 sec-1, for example, the viscosity decreased from 15,750 cp at 298 K to 418 cp at 353 K.

However, these w/o emulsions were substantially less viscous than the original bitumen at a given temperature, indicating the dilution of bitumen by pyrrolidine.

The viscosity of the bitumen measured by the same rheometer was 9,040 cp at 323 K and

690 cp at 353 K. Newtonian behavior was confirmed for the bitumen sample as shown in Figures 6A-6C. At 298 K, the bitumen viscosity was not measured by the rheometer because of the limitation in torque. However, this viscosity can be estimated to be 447,000 cp at 298 K using a viscosity correlation for this bitumen obtained from measurements made using an in-line viscometer. In comparison with the original bitumen, o/w emulsions created by different pyrrolidine concentrations are 4 to 6 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K. The viscosity and the amount of bitumen in o/w emulsions indicate that o/w emulsions could be an effective bitumen carrier that contains a large amount of bitumen with a significantly lower viscosity than the viscosity of the original bitumen. Only a small amount of pyrrolidine (0.5 wt%) was enough to create a single-phase o/w emulsion at a wide range of temperatures.

Discussion

This section first compares the main results obtained using three organic alkalis (DEA, TETA, and pyrrolidine), and then discuss the effect of the chemical structure of organic alkalis on the bitumen emulsification. The difference between the three different organic alkalis can be attributed largely to difference of the organic alkalis as the cosolvent in the bitumen/NaCl- brine/alkali mixture.

The properties of DEA, pyrrolidine, and TETA are summarized in Table 5. DEA and pyrrolidine are secondary amines and similar to each other in terms of MW and chemical formula. However, an important difference is that DEA has an aliphatic hydrocarbon chain, whereas pyrrolidine has a cyclic structure. TETA contains three two-carbon aliphatic segments and 4 nitrogens. Figures 7A-7D, 8A-8D, 9A-9D, 10A-10D, 11A-11D, and 12A-12D show bitumen emulsification with DEA and TETA.

Table 5. Properties of Organic Alkalis (DEA, TETA, and pyrrolidine).

TETA was effective in o/w emulsification of bitumen only at high temperatures. At WOR

7:3 and 1,000 ppm, for example, TETA gave a single-phase o/w emulsion at 373 K (Figures 8A-

8D). At temperatures below 373 K, however, an o/w emulsion with a small amount of bitumen was created along with an excess bitumen phase. With four nitrogen atoms in TETA, TETA is the most polar compound among the three organic alkalis, resulting in a large solubility in water.

The high polarity tends to make TETA sensitive to temperature in terms of affinity for the bitumen in the presence of water. It is likely that TETA’s polarity is too high for o/w emulsification of the bitumen for a wide range of temperatures.

In comparison to DEA and TETA, pyrrolidine created the single-phase o/w emulsion behavior at a wider range of temperatures. Also, the o/w emulsions created with pyrrolidine showed superior fluidity and rapid coalescence behavior after mixing when an o/w emulsion coexisted with an excess oil phase. These qualitative observations (in addition to emulsion color and texture) are widely used to identify low interfacial tension emulsions.

Potential reasons for pyrrolidine to be superior to DEA and TETA as cosolvent may include the higher level of affinity for bitumen, which is often highly asphaltic. The steric effect of the organic alkali as cosolvent is an important factor that affects the shape of the cosolvent, which in turn affects the size of asphaltenes aggregation in the bitumen emulsification.

Asphaltenes are a group of complex compounds with multi-benzene rings. Planar molecules (e.g., cyclic hydrocarbons due to the steric effect on their shapes) can fit into the asphaltene structure and replace asphaltene molecules with relatively small hydrocarbons. For example, cyclohexanol disaggregates asphaltenes whereas 1-hexanol aggregates asphaltenes, although they are similar in terms of MW and chemical formula. Without wishing to be bound by theory, the steric effect appears to make pyrrolidine more compatible with the asphaltic bitumen than DEA and TETA. Although pyrrolidine has a greater polarity than DEA according to Table 5, this example suggests that the steric effect on the molecular shape is more important than polarity as cosolvent to create o/w emulsions with the bitumen studied.

The Hansen solubility dispersion parameter can be a good indicator for the affinity for bitumen. For example, the disaggregation of asphaltenes can be observed when the Hansen solubility dispersion parameter of the chemical increases from 14.5 to 20. The Hansen solubility dispersion parameter is 14.9 for DEA and 17.9 for pyrrolidine. Based on the relationship between the dispersion parameter and asphaltene aggregation, the size of asphaltene aggregation with pyrrolidine could be about 12% smaller than that with DEA.

Comparison of different organic alkalis for the same bitumen indicates that it is important to consider the affinity of the organic alkali as cosolvent for bitumen for o/w emulsification. There are possible parameters that can be used for selection of organic alkalis for o/w

emulsification of bitumen, such as molecular structure and the Hansen solubility parameter. Conclusions

This example describes the fundamental data of phase behavior and viscosity for emulsions created by mixtures of Athabasca bitumen, pyrrolidine, and NaCl brine. The emulsion phase behavior was summarized by 111 samples with different pyrrolidine concentrations, brine salinities, and WORs at 373 K. Viscosities and bitumen contents in emulsion were measured at 298 K, 323 K and 353 K for selected emulsion samples at 7:3 WOR and 1,000 ppm salinity. Then, the main results with pyrrolidine were compared with the previously published data with two other organic alkalis, DEA and TETA, for the same bitumen as the bitumen used in this research. Conclusions are as follows:

It was possible to create o/w emulsions by adding a small amount of pyrrolidine to Athabasca bitumen and NaCl brine. Results showed that o/w emulsions appeared at low pyrrolidine concentrations (below 20 wt% and as low as 0.5 wt%) and low salinities (0 and 1,000 ppm). As pyrrolidine concentration increased, w/o emulsions appeared. A single-phase diluted bitumen was observed at 90 wt% pyrrolidine in the aqueous solution.

Single-phase o/w emulsions, which maximize the utilization of aqueous phase as a bitumen carrier, were observed at various conditions at 373 K: (1) for WOR 9:1, 1 to 5 wt% pyrrolidine at 1,000 ppm, (2) for WOR 7:3, 0.5 to 5 wt% pyrrolidine at 0 and 1,000 ppm, and (3) for WOR 5:5, 1 to 10 wt% pyrrolidine at 0 ppm. For samples of 0.5 wt% pyrrolidine with WOR 7:3 at 1,000 ppm, a single-phase o/w emulsion was observed for all temperatures from 298 K to 373 K.

The o/w emulsions created in this example were much less viscous than the original bitumen. They were 4 to 6 orders of magnitude less viscous at 298 K, 2 to 3 orders of magnitude less viscous at 323 K, and 1 to 2 orders of magnitude less viscous at 353 K.

Pyrrolidine was superior to DEA and TETA as cosolvent for o/w emulsification of the bitumen studied. Analysis of the results indicates that it is important to consider the affinity of the organic alkali for bitumen for o/w emulsification at a wide range of temperatures. Important factors for this purpose include the polarity, the steric effect that affects the molecular shape, and the Hansen solubility parameter of the organic alkali to be used.

The compositions, systems, and methods of the appended claims are not limited in scope by the specific compositions, systems, and methods described herein, which are intended as illustrations of a few aspects of the claims. Any compositions, systems, and methods that are functionally equivalent are intended to fall within the scope of the claims. Various modifications of the compositions, systems, and methods in addition to those shown and described herein are intended to fall within the scope of the appended claims. Further, while only certain

representative compositions, systems, and method steps disclosed herein are specifically described, other combinations of the compositions, systems, and method steps also are intended to fall within the scope of the appended claims, even if not specifically recited. Thus, a combination of steps, elements, components, or constituents may be explicitly mentioned herein or less, however, other combinations of steps, elements, components, and constituents are included, even though not explicitly stated.

The term“comprising” and variations thereof as used herein is used synonymously with the term“including” and variations thereof and are open, non-limiting terms. Although the terms “comprising” and“including” have been used herein to describe various embodiments, the terms “consisting essentially of’ and“consisting of’ can be used in place of“comprising” and “including” to provide for more specific embodiments of the invention and are also disclosed.

Other than where noted, all numbers expressing geometries, dimensions, and so forth used in the specification and claims are to be understood at the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claims, to be construed in light of the number of significant digits and ordinary rounding approaches.

Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of skill in the art to which the disclosed invention belongs. Publications cited herein and the materials for which they are cited are specifically incorporated by reference.

Claims

WHAT IS CLAIMED IS:

1. A method for producing a hydrocarbon comprising:

injecting steam and a volatile cyclic amine into a subterranean formation containing a heavy hydrocarbon to produce an oil-in- water emulsion in situ;

wherein the oil-in-water emulsion comprises the heavy hydrocarbon, water, an anionic surfactant, and a cosolvent; and

wherein the volatile cyclic amine is injected in an effective amount to:

(I) form the anionic surfactant in situ upon contact with the heavy

hydrocarbon; and

(II) provide excess unreacted volatile cyclic amine that acts as the co-solvent.

2. A method for producing a hydrocarbon comprising:

injecting steam and a volatile cyclic amine into a subterranean formation containing a heavy hydrocarbon;

wherein the volatile cyclic amine is injected in an effective amount to:

(I) form an anionic surfactant in situ upon contact with the heavy

hydrocarbon; and

(II) provide excess unreacted volatile cyclic amine; and

wherein the excess unreacted volatile cyclic amine acts as a co-solvent in an oil-in-water emulsion formed in situ in the subterranean formation by injection of the steam and the volatile cyclic amine.

3. A method for producing a hydrocarbon comprising:

injecting steam and a volatile cyclic amine into a subterranean formation containing a heavy hydrocarbon to produce an oil-in-water emulsion;

wherein the oil-in-water emulsion comprises the heavy hydrocarbon, water, an anionic surfactant, and a cosolvent;

wherein the anionic surfactant is formed in situ upon contact of the volatile cyclic amine with the heavy hydrocarbon; and wherein the co-solvent comprises excess unreacted volatile cyclic amine.

4. The method of any of claims 1-3, wherein the heavy hydrocarbon comprises a dense or high viscosity crude oil, bitumen, or a combination thereof.

5. The method of any of claims 1-4, wherein the heavy hydrocarbon comprises an oil sand.

6. The method of any of claims 1-5, wherein the volatile cyclic amine has an atmospheric pressure boiling point of less than or equal to 105°C, less than or equal to 100°C, less than or equal to 95 °C, or less than or equal to 90°C.

7. The method of any of claims 1-6, wherein the volatile cyclic amine is an aliphatic amine.

8. The method of any of claims 1-7, wherein the volatile cyclic amine exhibits a molecular weight of 85.0 g/mol or less, a molecular weight of 80.0 g/mol or less, or a molecular weight of 75.0 g/mol or less.

9. The method of any of claims 1-8, wherein the volatile cyclic amine exhibits a pKa of at least 10.0.

10. The method of any of claims 1-9, wherein the volatile cyclic amine does not comprise pyrrolidone, pyridine, piperidine, morpholine, pyrrole, cyclohexylamine, or a combination thereof.

11. The method of any of claims 1-10, wherein the volatile cyclic amine comprises pyrrolidine.

12. The method of any of claims 1-11, wherein the volatile cyclic amine is added to the steam at a concentration of from 0.5% to 30% by weight based on the total weight of the volatile cyclic amine and steam, such as from 0.5% to 20% by weight based on the total weight of the volatile cyclic amine and steam.

13. The method of any of claims 1-12, wherein the volatile cyclic amine is added to the steam at a concentration of greater than 5% by weight based on the total weight of the volatile cyclic amine and steam

14. The method of any of claims 1-13, wherein the steam further comprises an additional volatile amine or ammonia.

15. The method of claim 14, wherein the additional volatile amine has an atmospheric pressure boiling point of less than or equal to 145° C, such as an atmospheric pressure boiling point of less than or equal to 135° C.

16. The method of any of claims 14-15, wherein the additional volatile amine has a pK_aof at least 4.95, such as a pK_aof at least 5.0.

17. The method of any of claims 14-16, wherein additional volatile amine is selected from the group consisting of methyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethyl amine, isopropyl amine, n-propyl amine, diethyl amine, 1,1 -dimethyl hydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine, methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine, ethylenediamine, 3-methoxypropylamine, N,N-diethylhydroxylamine, morpholine, pyrrole, cyclohexylamine and combinations thereof.

18. The method of any of claims 1-17, wherein the steam further comprises a co- solvent.

19. The method of claim 18, wherein the co- solvent is selected from the group consisting of an alcohol, an aldehyde, a ketone, an ether, an ester, an amide, a hydrocarbon, or a combination thereof, such as tetrahydrothiophene, tetrahydrofuran, isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec -butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol, methanol, or combinations thereof.

20. A method for producing a hydrocarbon comprising:

wherein the volatile cyclic amine is injected in an effective amount to form the anionic surfactant in situ upon contact with the heavy hydrocarbon; and

wherein the volatile cyclic amine has an atmospheric pressure boiling point of 100°C or less.

21. The method of claim 20, wherein the heavy hydrocarbon comprises a dense or high viscosity crude oil, bitumen, or a combination thereof.

22. The method of any of claims 20-21, wherein the heavy hydrocarbon comprises an oil sand.

23. The method of any of claims 20-22, wherein the volatile cyclic amine has an atmospheric pressure boiling point of less than or equal to 95°C, or less than or equal to 90°C.

24. The method of any of claims 20-23, wherein the volatile cyclic amine is an aliphatic amine.

25. The method of any of claims 20-24, wherein the volatile cyclic amine exhibits a molecular weight of 85.0 g/mol or less, a molecular weight of 80.0 g/mol or less, or a molecular weight of 75.0 g/mol or less.

26. The method of any of claims 20-25, wherein the volatile cyclic amine exhibits a pKa of at least 10.0.

27. The method of any of claims 20-26, wherein the volatile cyclic amine comprises pyrrolidine.

28. The method of any of claims 20-27, wherein the volatile cyclic amine is added to the steam at a concentration of from 0.5% to 30% by weight based on the total weight of the volatile cyclic amine and steam, such as from 0.5% to 20% by weight based on the total weight of the volatile cyclic amine and steam.

29. The method of any of claims 20-28, wherein the volatile cyclic amine is added to the steam at a concentration of greater than 5% by weight based on the total weight of the volatile cyclic amine and steam

30. The method of any of claims 20-29, wherein the steam further comprises an additional volatile amine or ammonia.

31. The method of claim 30, wherein the additional volatile amine has an atmospheric pressure boiling point of less than or equal to 145° C, such as an atmospheric pressure boiling point of less than or equal to 135° C.

32. The method of any of claims 30-31, wherein the additional volatile amine has a pK_aof at least 4.95, such as a pK_aof at least 5.0.

33. The method of any of claims 30-32, wherein additional volatile amine is selected from the group consisting of methyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethyl amine, isopropyl amine, n-propyl amine, diethyl amine, 1,1 -dimethyl hydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine, methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine, ethylenediamine, 3-methoxypropylamine, N,N-diethylhydroxylamine, morpholine, pyrrole, cyclohexylamine and combinations thereof.

34. The method of any of claims 20-33, wherein the steam further comprises a co-solvent.

35. The method of claim 34, wherein the co-solvent is selected from the group consisting of an alcohol, an aldehyde, a ketone, an ether, an ester, an amide, a hydrocarbon, or a combination thereof, such as tetrahydrothiophene, tetrahydrofuran, isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec -butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol, methanol, or combinations thereof.

36. A method for producing a hydrocarbon comprising:

injecting steam and an aliphatic cyclic amine into a subterranean formation containing a heavy hydrocarbon;

wherein the aliphatic cyclic amine is injected in an effective amount to form the anionic surfactant in situ upon contact with the heavy hydrocarbon; and

wherein the aliphatic cyclic amine exhibits a molecular weight of 80.0 g/mol or less.

37. The method of claim 36, wherein the heavy hydrocarbon comprises a dense or high viscosity crude oil, bitumen, or a combination thereof.

38. The method of any of claims 36-37, wherein the heavy hydrocarbon comprises an oil sand.

39. The method of any of claims 36-38, wherein the aliphatic cyclic amine has an atmospheric pressure boiling point of less than or equal to 105°C, less than or equal to 100°C, less than or equal to 95°C, or less than or equal to 90°C.

40. The method of any of claims 36-39, wherein the aliphatic cyclic amine exhibits a molecular weight of 75.0 g/mol or less.

41. The method of any of claims 36-40, wherein the aliphatic cyclic amine exhibits a pKa of at least 10.0.

42. The method of any of claims 36-41, wherein the aliphatic cyclic amine comprises pyrrolidine.

43. The method of any of claims 36-42, wherein the aliphatic cyclic amine is added to the steam at a concentration of from 0.5% to 30% by weight based on the total weight of the aliphatic cyclic amine and steam, such as from 0.5% to 20% by weight based on the total weight of the aliphatic cyclic amine and steam.

44. The method of any of claims 36-43, wherein the aliphatic cyclic amine is added to the steam at a concentration of greater than 5% by weight based on the total weight of the aliphatic cyclic amine and steam.

45. The method of any of claims 36-44, wherein the steam further comprises an additional volatile amine or ammonia.

46. The method of claim 45, wherein the additional volatile amine has an atmospheric pressure boiling point of less than or equal to 145° C, such as an atmospheric pressure boiling point of less than or equal to 135° C.

47. The method of any of claims 45-46, wherein the additional volatile amine has a pK_aof at least 4.95, such as a pK_aof at least 5.0.

48. The method of any of claims 45-47, wherein additional volatile amine is selected from the group consisting of methyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethyl amine, isopropyl amine, n-propyl amine, diethyl amine, 1,1 -dimethyl hydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine, methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine, ethylenediamine, 3-methoxypropylamine, N,N-diethylhydroxylamine, morpholine, pyrrole, cyclohexylamine and combinations thereof.

49. The method of any of claims 36-48, wherein the steam further comprises a co-solvent.

50. The method of claim 49, wherein the co-solvent is selected from the group consisting of an alcohol, an aldehyde, a ketone, an ether, an ester, an amide, a hydrocarbon, or a combination thereof, such as tetrahydrothiophene, tetrahydrofuran, isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec -butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol, methanol, or combinations thereof.

51. A method for producing a hydrocarbon comprising:

injecting steam, a co-solvent, and a volatile amine into a subterranean formation containing a heavy hydrocarbon to produce an oil-in-water emulsion in situ;

wherein the oil-in-water emulsion comprises the heavy hydrocarbon, water, an anionic surfactant, and the co- solvent; and

wherein the volatile amine is injected in an effective amount to form the anionic surfactant in situ upon contact with the heavy hydrocarbon.

52. A method for producing a hydrocarbon comprising:

injecting steam, a co-solvent, and a volatile amine into a subterranean formation containing a heavy hydrocarbon;

wherein the volatile amine is injected in an effective amount to form an anionic surfactant in situ upon contact with the heavy hydrocarbon.

53. A method for producing a hydrocarbon comprising:

injecting steam, a co-solvent, and a volatile amine into a subterranean formation containing a heavy hydrocarbon to produce an oil-in-water emulsion;

wherein the anionic surfactant is formed in situ upon contact of the volatile amine with the heavy hydrocarbon.

54. The method of any of claims 51-53, wherein the heavy hydrocarbon comprises a dense or high viscosity crude oil, bitumen, or a combination thereof.

55. The method of any of claims 51-54, wherein the heavy hydrocarbon comprises an oil sand.

56. The method of any of claims 51-55, wherein the volatile amine has an atmospheric pressure boiling point of less than or equal to 145°C, less than or equal to 140°C, less than or equal to 135°C, less than or equal to 130°C, less than or equal to 125°C, less than or equal to 120°C, less than or equal to 115°C, less than or equal to 110°C, less than or equal to 105°C, less than or equal to 100°C, less than or equal to 95°C, or less than or equal to 90°C.

57. The method of any of claims 51-56, wherein the volatile amine comprises a primary amine, a secondary amine, or a tertiary amine.

58. The method of any of claims 51-57, wherein the volatile amine comprises a cyclic amine.

59. The method of any of claims 51-58, wherein the volatile amine comprises an aliphatic amine.

60. The method of any of claims 51-58, wherein the volatile amine comprises an aromatic amine.

61. The method of any of claims 51-60, wherein the volatile cyclic amine exhibits a molecular weight of 125.0 g/mol or less, a molecular weight of 120.0 g/mol or less, 115.0 g/mol or less, a molecular weight of 110.0 g/mol or less, 105.0 g/mol or less, a molecular weight of 100.0 g/mol or less, 95.0 g/mol or less, a molecular weight of 90.0 g/mol or less, 85.0 g/mol or less, a molecular weight of 80.0 g/mol or less, or a molecular weight of 75.0 g/mol or less.

62. The method of any of claims 51-61, wherein the volatile amine exhibits a pKa of at least 5.0, or a pKa of at least 10.0.

63. The method of any of claims 51-62, wherein the volatile amine is added to the steam at a concentration of from 0.5% to 30% by weight based on the total weight of the volatile amine and steam, such as from 0.5% to 20% by weight based on the total weight of the volatile amine and steam.

64. The method of any of claims 51-63, wherein volatile amine is selected from the group consisting of methyl amine, dimethyl amine, trimethyl amine, diethyl amine, ethyl amine, isopropyl amine, n-propyl amine, diethyl amine, 1,1 -dimethyl hydrazine, isobutyl amine, n-butyl amine, pyrrolidone, triethylamine, methyl hydrazine, piperidine, dipropylamine, hydrazine, pyridine, ethylenediamine, 3-methoxypropylamine, N,N-diethylhydroxylamine, morpholine, pyrrole, cyclohexylamine, pyrrolidine, and combinations thereof.

65. The method of any of claims 51-65, wherein the co-solvent is selected from the group consisting of an alcohol, an aldehyde, a ketone, an ether, an ester, an amide, a hydrocarbon, and combinations thereof.

66. The method of any of claims 51-65, wherein the co-solvent is selected from the group consisting of tetrahydrothiophene, tetrahydrofuran, isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl alcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol, n-hexyl alcohol, sec-hexyl alcohol, methanol, and combinations thereof.

67. The method of any of claims 51-66, wherein the co-solvent has an atmospheric pressure boiling point of less than or equal to 145°C, less than or equal to 140°C, less than or equal to 135°C, less than or equal to 130°C, less than or equal to 125°C, less than or equal to 120°C, less than or equal to 115°C, less than or equal to 110°C, less than or equal to 105°C, less than or equal to 100°C, less than or equal to 95°C, or less than or equal to 90°C.