CA2958449C

CA2958449C - Methods for accelerating recovery of heavy hydrocarbons with co-injection of steam and volatile agent

Info

Publication number: CA2958449C
Application number: CA2958449A
Authority: CA
Inventors: Ishan Deep S. Kochhar; Brent Donald Seib
Original assignee: FCCL Partnership
Current assignee: FCCL Partnership
Priority date: 2016-02-16
Filing date: 2017-02-16
Publication date: 2024-01-09
Anticipated expiration: 2037-02-16
Also published as: CA2958449A1

Abstract

In a process for producing hydrocarbons from a subterranean reservoir comprising viscous hydrocarbons and an organic acid, steam is injected into the reservoir to heat and mobilize the viscous hydrocarbons and mobilized hydrocarbons are produced from the reservoir. In one embodiment, a vapor of n-butylamine or n-propylamine is also injected into the reservoir to react with the organic acid to form a surfactant. The surfactant reduces the interfacial tension between hydrocarbons and water, thus accelerating the rate of hydrocarbon production. In a different embodiment, a volatile amine for injection may be selected from amines that are more volatile than steam in the reservoir and have boiling points of about 45°C to about 80 °C. A mixture comprising steam and about 0.1 wt% to about 0.2 wt% of the volatile amine may be injected.

Description

METHODS FOR ACCELERATING RECOVERY OF HEAVY
HYDROCARBONS WITH CO-INJECTION OF STEAM AND VOLATILE AGENT
FIELD
The present invention relates to methods for producing hydrocarbons from a hydrocarbon reservoir and, in particular, to methods that utilize volatile amines to accelerate the recovery of hydrocarbons from the reservoir during enhanced oil recovery processes.
BACKGROUND
Hydrocarbon resources such as bituminous sands (also known as oil sands, reservoirs, deposits or formations) can be extracted in situ by lowering the viscosity of the hydrocarbons to mobilize the hydrocarbons so that they can be moved to, and recovered from, a production well. Many thermally-driven processes, such as steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS), have been developed to reduce the viscosity and mobilize the hydrocarbons for better recovery. Conventional in situ thermal recovery processes typically involve the use of one or more "injection" and "production"
wells drilled into the reservoir, whereby a heated fluid (e.g. steam) can be injected into the reservoir through the injection wells and hydrocarbons can be retrieved from the reservoir through the productions wells.
By way of example, a SAGD system typically comprises at least one pair of steam injection and hydrocarbon production wells (a "well pair") located in a subterranean reservoir. Both wells have generally horizontal, perforated terminal sections.
A perforated section may have any type of opening in the wellbore for fluid communication with the reservoir, and may include slotted casing. The horizontal section of the injection well is typically located above the horizontal section of the production well, normally by a few meters. The injection well is used to inject a heated fluid, for example steam, into the reservoir, transferring heat from the fluid to the bitumen and reducing the viscosity of the bitumen. The softened hydrocarbons and condensed steam flow and drain downward due to gravity, leaving behind a porous region or "steam chamber" that is permeable to gas Date recue/Date received 2023-06-09 and steam. As more steam is injected into the reservoir, it rises from the injection well, permeating the chamber and condensing at its edge (often referred to as the "steam chamber front"). The steam chamber front is the interface area of the steam chamber and the bitumen in the formation. The steam continues to transfer heat to more hydrocarbons, growing the steam chamber over time. The mobilized hydrocarbons and condensate continue to drain downwardly under gravity, and are collected by the generally horizontal section of the production well, from which the hydrocarbons are produced or recovered.
Multiple well pairs may be arranged at a well pad or within the reservoir to form a well pattern. Additional injection or production wells, such as a well drilled using Wedge WelITM technology, may also be provided.
In a typical CSS process, a single well may be used to alternately inject steam into the reservoir or produce a fluid from the reservoir. The alternation may be repeated or cycled, hence known as cyclic steam stimulation. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. A
steam chamber may also develop in a CSS process.
Solvents or other chemical additives have been used to enhance in situ thermal recovery of hydrocarbons in the reservoir. For example, surfactants, which are compounds that lower the surface tension of a liquid, the interfacial tension (IFT) between two liquids, or between a liquid and a solid, have been used to improve recovery processes. For instance, surfactants may act as detergents, wetting agents, emulsifiers, foaming agents, or dispersants, to facilitate the drainage of the softened bitumen to the production well.
It has been suggested in US7,938,183 to Hart et al. that amines and ammonia may be used to enhance recovery of heavy hydrocarbons, by forming surfactants in situ. The amines and ammonia may be injected with water, steam or an oil solvent to combine with the heavy hydrocarbons to promote the transport of the heavy hydrocarbons. It was suggested that any amine might be useful in this context and particularly those with a boiling point temperature (BP) of no more than 135 C at normal atmospheric pressure and an acidity (pKu) of at least 5.0, or BP of no more than 145 C and pKõ of at least 4.95.
Many exemplary amines were proposed, but amines having both a low boiling point and a comparatively high pKõ, such as climethyl amine (BP =- -1.7C , PKa = 10.68), were considered as particularly desirable. It was suggested that the amine or ammonia to be added can have concentrations from about 50 to 50,000 ppm by weight in the steam or solvent, such as 1000 to 10,000 ppm. It was believed that the amine and ammonia can react with naphthenic acids or carboxylic acids in the formation to form anionic surfactants, which can act as oil-emulsifying soaps. The hydrophilic-lipophilic balance (H.L.B) of the surfactant formed in situ could be optimized for maximum utility by manipulating the alkyl groups on the amine. It was predicted that ammonia provided the highest bitumen recovery, and recovery would be reduced monotonically with amines that are less volatile, more hydrophobic and weaker bases. Tests were conducted with 500 ppm of selected amines and ammonia, and addition of dimethylamine with heptane showed the highest percentage of bitumen recovery.
Organic solvents, such as an alkane or alkene, have also been used to improve recovery by diluting the softened bitumen to increase its mobility to the production well.
Finally, volatile agents, such as volatile amines, which are thought to be carried with the steam to the hydrocarbons, have also been suggested to enhance recovery, but the use thereof is plagued by the difficult path from the wellhead to the steam chamber front (which even the smallest molecules are unlikely to pass through).
Challenges remain in connection with the use of chemical additives under in situ conditions in thermally-driven hydrocarbon recovery processes. There is a need for methods for accelerating production of hydrocarbons from subterranean reservoirs, such methods being capable of enhancing known conventional hydrocarbon production methods. While some guidance has been provided, it still remains difficult to select the optimal additives for a given thermal in situ recovery process. This difficulty is coupled with the fact that it is costly and time consuming to conduct field tests for selecting suitable injection additives, as it could take years of operating a number of well pairs to obtain reliable results from the field. As a result, commercialization of many of the previously suggested recovery techniques has yet to be realized. Additional guidance is desirable for selecting optimal additives and dosages for commercialization or even field testing.

SUMMARY
Accordingly, in a first aspect of the present disclosure there is provided a method of producing hydrocarbons from a subterranean reservoir comprising viscous hydrocarbons and an organic acid in a recovery process wherein steam is injected into the reservoir to heat and mobilize the viscous hydrocarbons and mobilized hydrocarbons are produced from the reservoir. The method comprises injecting a vapor of n-butylamine or n-propylamine into the reservoir to react with the organic acid to form a surfactant, the surfactant capable of reducing an interfacial tension between a hydrocarbon and water. In this method, a mixture comprising steam and about 0.1 wt% to about 0.2 wt% of n-butylarnine or n-propylamine may be injected into the reservoir. The steam and the vapor of n-butylamine or n-propylamine may be injected into the reservoir at a temperature of about 170 C to about 240 C. The organic acid may comprise a naphthenic acid.
The n-butylamine or n-propylamine may be injected into the reservoir at a concentration selected to reduce a total acid number in a fluid produced from the reservoir by at least 10%, or 30%, or 70%. The n-butylamine or n-propylamine may be injected into the reservoir at a rate selected to accelerate hydrocarbon production from the reservoir by at least about 10% to about 25%. In an embodiment, n-butylamine is injected into the reservoir. In another embodiment, n-propylamine is injected into the reservoir. In a further embodiment, both n-butylamine and n-propylamine are injected into the reservoir.
The steam may be injected at a pressure of about 2 MPa to about 4 MPa. The n-butylamine or n-propylamine may be injected into the reservoir for a period of 9 to 24 months. The n-butylamine or n-propylamine may be injected at different injection concentrations at different times. When n-butylamine or n-propylamine is injected into the reservoir, a rate of steam injection may be increased.
It has been recognized, in view of the tested performance of n-propylamine and n-butylamine, it can be reasonably expected that, for candidate amines that otherwise satisfy various other selection factors and criteria, those that are more volatile than steam under reservoir conditions and have a boiling point (BP) within the range of about 45 C
and about 80 C can be expected to be good candidates for accelerating oil production.

Thus, in a different aspect of the present disclosure, there is provided a method of producing hydrocarbons from a subterranean reservoir comprising viscous hydrocarbons and an organic acid in a recovery process wherein steam is injected into the reservoir to heat and mobilize the viscous hydrocarbons and mobilized hydrocarbons are produced 5 from the reservoir. The method comprises injecting a vapor of a volatile amine into the reservoir to react with the organic acid to form a surfactant, the surfactant capable of reducing an interfacial tension between a hydrocarbon and water, wherein the volatile amine is selected such that the selected volatile amine is more volatile than steam in the reservoir, and has a boiling point of about 45 C to about 80 C. In this method, a mixture comprising steam and about 0.1 wt% to about 0.2 wt% of the selected volatile amine may be injected into the reservoir. The steam and the selected volatile amine may be injected into the reservoir at an injection temperature of about 170 C to about 240 C. The organic acid may comprise a naphthenic acid. The selected volatile amine may be injected into the reservoir at a concentration selected to reduce a total acid number in a __ fluid produced from the reservoir by at least 10%, or 30%, or 70%. The selected volatile amine may be injected into the reservoir at a rate selected to accelerate hydrocarbon production from the reservoir by at least 10% to 25%. The selected volatile amine may have a pKõ of at least 1Ø The selected volatile amine may be more soluble in the hydrocarbons than in water at a steam chamber front in the reservoir. The selected volatile amine may have a linear hydrocarbon chain. The volatile amine may comprise a basic component and a hydrocarbon component. The basic component may comprise at least one amino group. The volatile amine may be thermally stable. The selected volatile amine may be a primary amine. A solvent may also be injected into the reservoir to assist production of hydrocarbons from the reservoir. The solvent may comprise propane, butane, or both. The steam may be injected at a pressure of about 2 MPa to about 4 MPa.
The volatile amine may be injected into the reservoir for a period of 9 to 24 months. The volatile amine may be injected at different injection concentrations at different times.
When the volatile amine is injected into the reservoir, a rate of steam injection may be increased.

BRIEF DESCRIPTION OF THE DRAWINGS
FIGS. IA and IB are schematic diagrams illustrating a steam-assisted gravity drainage (SAGD) arrangement according to embodiments herein;
FIG. 2 is as schematic diagram showing an experimental steam soak test apparatus according to embodiments herein;
FIGS. 3A, 3B, 3C, 3D, 3E, 3F, 3G and 3H are data graphs showings experimental steam soak test results for various tested compounds;
FIG. 4 shows the vapor pressure curve of various volatile amines compared to water;
FIGS. 5A, 5B, and 5C show the solubility of various volatile amines in oil (Fig.
5A) and water (Fig. 5B), and the relative solubility between oleic and aqueous phases (Fig. 5C), respectively, at the pressure of 2.5 MPa;
FIG. 6 shows the K values (I/solubility) of volatile amines in the oleic phase at various pressures from 1 MPa to 4 MPa;
FIG. 7 shows the K values (I/solubility) of volatile amines in the aqueous phase at various pressures from 1 MPa to 4 MPa;
FIG. 8 is a flowchart illustrating a hypothetical process for recovery of hydrocarbons from the reservoir of Fig. 1, illustrative of an example embodiment;
FIG. 9 shows a schematic diagram of the hypothetical process of FIG. 8; and FIGS. 10 and 11 are line graphs showing predicated acceleration of oil production rates and changes in instantaneous steam-to-oil ratio, when n-butylamine is injected at 0.2 wt%, in comparison with pure steam injection.

DESCRIPTION OF THE EMBODIMENTS
According to embodiments herein, methods for producing hydrocarbons from a subterranean hydrocarbon reservoir are provided.
Methods for producing oil from a subterranean hydrocarbon reservoir of bituminous sands in a steam-assisted in situ recovery process are provided. In particular, the hydrocarbon reservoir contains viscous hydrocarbons and one or more organic acids that can react with suitable amines to form surfactants, which can reduce the interfacial tension (IFI) between oil and water and thus improve mobility or drainage rate of mobilized hydrocarbons in the reservoir. Steam is injected to heat and mobilize the viscous hydrocarbons in the reservoir. A selected amine is also injected to react with the organic acids to form the surfactant.
The inventors of the present application recognized that the conventional teaching did not provide adequate guidance for selecting the optimal volatile amine to be injected with steam in a steam-assisted gravity drainage (SAGD) operation to accelerate oil production. In particular, it has been recognized that the previously available data and information might be inconsistent and might not be reliable. It is further recognized that previously considered less preferable compounds may in fact provide unexpected improvement, and may perform better than other amines. Further guidance on selecting potentially optimal amines for accelerating oil production by forming surfactants in situ is required.
The inventors have discovered that, in at least some steam-assisted in situ recovery processes, n-propylamine and n-butylamine can provide much superior performance as compared to other volatile amines such as dimethylamine, which was previously taught as a preferred choice. This result was unexpected and surprising from previous teaching, but is supported by laboratory testing results.
The inventors have also recognized that, while it was previously taught that the boiling point (BP) of a candidate amine was an important factor to be considered when selecting the optimal amine and compounds with lower boiling points are preferred, for at least SAGD operations with maximum operating temperatures in the reservoir being higher than 150 C and below about 250 C , such as from about 170 C to about 240 C , an amine with a boiling point in the range of about 45 C to about 80 C is a better candidate in some embodiments (see further discussion below).
The inventors have further discovered that an optimal dosage of the injected volatile amine is 0.1 wt% to 0.2 wt% when co-injected with steam in a SAGD
operation, for accelerating hydrocarbon production.
Test results show that at least when the concentration of the injected volatile amine is in a certain range, such as from 0.1 wt % to 0.2 wt% based on the weight of the total injection fluid, n-propylamine and n-butylamine are expected to be more, or most, effective or efficient for accelerating oil recovery, as compared to dimethylamine and other amines that have been tested. This result is surprising in view of the teaching in the known literature.
In selected embodiments, the type of volatile agents that can be suitable candidates for use in an embodiment disclosed herein may be chosen based on a combination of a number of factors as discussed in detail below. Briefly, these factors may include the following.
The candidate volatile agents have vapor pressure profiles on the left hand side of the vapor pressure profile of water at the operating formation conditions, on a pressure-temperature chart as illustrated in FIG. 4. Ideally, a selected volatile agent would have vaporization and condensation properties or profiles closely matching those of water, subject to other factors described here and as can be appreciated by those skilled in the art.
The candidate volatile agents should have similar or higher reactivity with carboxylic acids or other organic acids present in the formation, as compared to propylamine or butylamine, for forming surfactants in situ. The candidate volatile agents are thus precursors for forming the surfactants. Reactivity of the selected surfactant precursors may be indicated by reduction of the total acid number (TAN) in the produced fluid from the formation. Thus, a selection factor may be whether the candidate volatile agent can provide sufficient TAN reduction in lab testing, such as by at least about 30%, or about 70%. The candidate volatile agents may also be selected so that surfactants formed in situ have a suitable hydrophilic-lipophilic balance (HLB), as can be appreciated by those skilled in the art.
It is further desirable that the candidate volatile agent has relatively high solubility in oil. For example, some organic acids such as naphthenic acids may be present in the bitumen or oil phase and dissolving into the oil phase would allow the surfactant precursors (including the volatile agent and the organic acids) to reach each other and react.
In selected embodiments, a candidate volatile agent may have a suitable molecular chain length, and can be a C3-C4 linear amine.
It is expected that co-injecting a small amount of a volatile agent, which is a suitable surfactant precursor as further described below, with steam into a steam chamber can result in one or more of the following: accelerated time to first oil production, reduced steam to oil ratio (SOR), reduced total acid number (TAN), or reduced residual oil saturation. The injected volatile agent is heated by steam and can travel or rise up to the steam front with steam. The injected volatile agent travels ahead of, or with, the steam front reacting with the residual oil in the reservoir, and condensing at the edges (e.g., interface area) of the steam chamber. The early injection of the volatile agent and steam, for example after well pair communication is established, into the reservoir at least focuses the dissolution of the volatile agent to that residual cold bitumen at the edges of the steam chamber, creating an increased drainage rate from the reservoir.
With the careful selection of the volatile agent, at least one of the time to first oil production, reduction in SOR, reduction in TAN, or reduction in the residual oil saturation can be optimized.
A number of factors are expected to influence the performance of the volatile agent. In order to provide an effect of reduced residual oil saturation in the reservoir, the volatile agent should be volatile enough to travel with or slightly ahead of the steam front. Heavier volatile agents typically have a higher boiling point and, as a result, remain near the wellbore, generally the injector wellbore. Such heavier volatile agents are not.
volatile enough to reach the steam front in a concentration sufficient to effect.
performance. To reach the steam chamber front, the BP of a volatile amine may need to be below about 120 C. For an increased portion of the vapor of the volatile amine to reach the steam chamber front, the BP may need to be below about 105 C.
However, for even better or optimal results, it is expected that the BP should be below about 80 C.
On the other hand, for the volatile agent, particularly volatile amine, to be able to 5 condense and remain largely in the liquid phase, the BP of the selected amine should be higher than the temperature at the steam chamber front or in the region near the steam chamber front. For example, in a SAGD operation, the temperature at the steam chamber front may typically from be from about 10-12 C to about 20 C. Thus, it is expected that amines with BP above 20 C may be suitable. For better or optimal performance, the BP
10 of the selected volatile amine may need to be above about 45 C.
For clarity, it is noted that BP (boiling point) as used herein refers to the temperature at the boiling point under normal conditions, namely at atmospheric pressure, unless otherwise specifically specified.
Lab test results support the expectation that to achieve better or optimal performance in selected embodiments, the boiling point of the volatile agent should not be too low and not too high. For example, volatile agents with BP between 20 C and 105 C may provide acceptable performance. Lab tests also showed that volatile amines with BP of about 45 C to about 80 C provided the optimal or best performance in the test conditions (see below). Without being limited to any particular theory, it is expected that liquid amine even when dissolved in water can penetrate reservoir oil and other fluids more readily than vapor amine. Liquid amine dissolved in the bitumen or the oil phase can directly interact and react with organic acids present therein. Thus, condensed amine in the liquid phase at the steam chamber front is expected to be more effective than vapor amine.
Without being limited to any particular theory, it is expected that volatile agents having boiling points in the range of 20 C to 80 C, particularly the range of about 45 C
to about 80 C, and having vaporization and condensation properties or profiles closely matching those of water, can both efficiently travel to the steam chamber front with or slightly before steam through the chamber regions at a higher temperature, and quickly condense and dissolve in oil and other fluids at the steam chamber front where the temperature is below about 20 C. If a volatile surfactant precursor is too volatile, it will be less effective as it would tend to stay in the vapor phase even after it has reached the steam chamber front. Of course, if a surfactant precursor is not volatile or not sufficiently volatile, it would be difficult to transport the surfactant precursor to the steam chamber front with steam. Conveniently, the temperature in the steam chamber drops significantly from the injection well to the steam chamber front, which allows effective transport of the selected volatile agent to the steam chamber front and then condensation at the steam chamber front. It should be noted that this factor is not the only selection factor. Some volatile compounds with a vapor pressure curve similar to that of water are not good candidates for the volatile agent as they do not rank high in view of other factors discussed above and below. As illustrated in FIG. 4, butylamine and propylamine have vapor pressure curves closely matching that of water at temperatures below about 250 C.
In comparison, ammonia and methylamine vapor pressure curves are less similar to that.
of water, and both ammonia and methylamine have much higher vapor pressures at temperatures below about 20 C. Of course, it should be noted that the vapor pressure curve is not the only selection criteria.
Another factor that should be considered when selecting the volatile agent is that it should have both a reasonably high solubility in oil and low solubility in water when the volatile agent is condensed at lower temperatures such as below about 20 C
to about 50 C. In other words, it is desirable that the volatile agent is more soluble in oil than in water at the temperature of the steam chamber front. Lab tests showed that volatile amines having relatively higher oil solubility and lower water solubility were more effective. Thus, volatile agents with higher oil solubility than water solubility are expected to be more effective. Butylamine and propylamine meet this requirement. In comparison, ammonia has a relatively high solubility in water at lower temperatures and a relatively high solubility in oil at higher temperatures. This suggests that a volatile amine having a hydrocarbon component may be preferred to help with dissolution of the amine in the oil phase.
Generally, it is expected that the volatile agents are more volatile than water at.
higher temperatures such as above 50 C. As noted above, volatile agents are typically on the left side of the water vapor pressure curve. Hence, these volatile agents will be at or ahead of the steam front when the injected steam and volatile agent travel from the injection point towards the steam chamber edge (chamber front). Being at or ahead of the steam front, these volatile agents should react with certain acids in the formation to form in situ surfactants which in turn assist in the reduction of interfacial tension (IFT) between oil and water.
As a surfactant precursor, it is of course desirable that the volatile agent once condensed at the steam chamber front will react quickly to form the desired surfactant(s).
Lab tests have shown that n-propylamine and n-butylarnine can exhibit sufficient reactivity with carboxylic acids, such as naphthenic acids, and other organic acids found in a typical bitumen formation to form suitable surfactants. Thus, in selected embodiments, a volatile agent is selected such that it has similar or higher reactivity with carboxylic acids or other organic acids present in the formation, as compared to n-pmpylamine or n-butylamine, for forming surfactants in situ. Reactivity of the selected volatile agent may be indicated by reduction of the total acid number (TAN) in the produced fluid from the formation. Lab tests showed that when n-butylamine or n-propylamine was used as the surfactant precursor or volatile agent, TAN in the tested formation sample could be reduced by from about 30% up to almost 100%, depending on the concentration of the injected volatile agent. In practice, for optimal economic performance, it may not be necessary to reduce TAN by 100%. In some embodiments, the volatile agents may be injected at concentrations sufficient to achieve at least 30%
TAN reduction, such as about 40% to about 50%, or up to 70% TAN reduction.
Thus, a selection factor may be whether the selected volatile agent can provide sufficient TAN
reduction in lab tests, such as by at least 30% with injection concentration of 0.2 wt%.
When the selected volatile agent has relatively high solubility in oil, it may facilitate formation of the surfactants when some organic acids such as naphthenic acids are present in the bitumen or oil phase, as dissolving the condensed volatile agent into the oil would allow the surfactant precursors to reach each other and react.
For improved performance of the formed surfactant, the surfactant precursors should also be selected so that the surfactants formed in situ from the surfactant.

precursors have a suitable hydrophilic-lipophilic balance (11LB), such as about 10.5 to about 11.
Ultimately, it is desirable that the oil phase in the formation fluid can have better mobility and can flow and drain faster towards the production well. To this end, it is expected that an oil-in-water emulsion can move through the formation at a faster speed than a water-in-oil emulsion. The inversion from a water-in-oil emulsion to an oil-in-water emulsion depends on the relative proportions of oil and water in the fluid.
Typically, an oil-in-water emulsion requires a relatively higher water content and a relatively lower oil content as compared to a water-in-oil emulsion. It is expected that when the IFT between oil and water is reduced, an oil-in-water emulsion is more likely to form at lower water content, or a water-in-oil emulsion can invert to an oil-in-water emulsion at lower water content. Forming oil-in-water emulsion with reduced water requirement can be beneficial as a similar or higher oil production rate may be achieved at a lower steam injection rate. Forming oil-in-water emulsion may be associated with.
reducing the viscosity of the hydrocarbons in the reservoir and enhancing drainage of the hydrocarbons to the production well.
In view of the factors discussed above, in selected embodiments, it is expected that short chain primary amines, such as C3-C4 linear primary amines, would provide the best performance. In some embodiments, where reduced performance may be acceptable or tolerable for either technical or economic reasons, the selected volatile agent may be a C2-C6 linear amine.
While possible volatile agents may include volatile amines, particularly methyl amine, ethyl amine, propyl amine, butyl amine, di-methyl amine, di-ethyl amine, di-propyl amine, tri-methyl amine, tri-ethyl amine, allyl amine and combinations thereof, the most preferred volatile agents are propyl amine (n-propylamine), butyl amine (n-butylamine), and combinations thereof.
It has also been discovered that the effectiveness and efficiency of the injection of the volatile agent are dependent on the injection concentration. For example, in selected conditions, when the concentration of the injected volatile agent is in a certain range such as from 1,000 ppm to 2,000 ppm by weight based on the total injection fluid, the injection of the volatile agent is more or most effective and efficient.
In various embodiments herein, the term "reservoir" refers to a subterranean or underground formation comprising recoverable oil (hydrocarbons) and the term .. "reservoir of bituminous sand(s)" refers to such a formation wherein at least some of the hydrocarbons are viscous and immobile and are disposed between or attached to sands.
In various embodiments herein, the terms "oil" or "hydrocarbon(s)" refers to bitumen, oil, heavy oil, oil sands, and other hydrocarbons in various states that may be produced from the production well penetrating the reservoir during conventional thermal-drive processes. For example, "heavy oil", "extra heavy oil", and "bitumen"
refer to hydrocarbons occurring in semi-solid or solid form and having a viscosity in the range of about 1,000 to over 1,000,000 centipoise (mPa.s or cP) measured at original in situ reservoir temperature. Herein, the terms "hydrocarbons", "heavy oil", "oil"
and "bitumen" are used interchangeably. Depending on the in situ density and viscosity of the hydrocarbons, the hydrocarbons may comprise, for example, a combination of heavy oil, extra heavy oil and bitumen. Heavy crude oil, for example, may be defined as any liquid petroleum hydrocarbon having an American Petroleum Institute (API) Gravity of less than about 20 and a viscosity greater than 1,000 mPa's. Oil may be defined, for example, as hydrocarbons mobile at typical reservoir conditions. Extra heavy oil, for .. example, may be defined as having a viscosity of over 10,000 m.Pass and about 1.0 API
Gravity. The API Gravity of bitumen ranges from about 12 to about 7 and the viscosity is greater than about 100,000 inPa.s. Native bitumen is generally non-mobile at typical native reservoir conditions.
A person skilled in the art will appreciate that an immobile formation or reservoir at initial (or original) conditions (e.g., temperature or viscosity) means that the reservoir has not been treated with heat or other means. Instead, it is in its original condition, prior to the recovery of hydrocarbons. Immobile formation means that the formation has not been mobilized through the addition of heat or other means.
The hydrocarbons in the reservoir of bituminous sands occur in a complex mixture comprising interactions between sand particles, fines (e.g., clay), and water (e.g., interstitial water) which may form complex emulsions during processing. The hydrocarbons derived from bituminous sands may contain other contaminant inorganic, organic or organometallic species which may be dissolved, dispersed or bound within suspended solid or liquid material. Accordingly, it remains challenging to separate 5 .. hydrocarbons from the bituminous sands in situ, which may impede production performance of the in situ process.
Production performance may be improved when a higher amount of oil is produced within a given period of time, or with a given amount of injected steam depending on the particular recovery technique used, or within the lifetime of a given 10 production well (overall recovery), or in some other manner as can be understood by those skilled in the art. For example, production performance may be improved by increasing the amount of hydrocarbons recovered within the steam chamber, increasing drainage rate of the fluid or hydrocarbon from the steam chamber to the production well, or both.
15 Increased (faster) oil flow or drainage rates can lead to more efficient oil production, and the faster flow or drainage rate of reservoir fluids (or formation fluids) within the formation can be indirectly indicated or measured by the increase in the rate of oil production. Techniques for measurement of oil production rates have been well developed and are known to those skilled in the art. Embodiments disclosed herein can improve production performance, such as in a manner described below.
It is understood that a method disclosed herein for producing hydrocarbons from a subterranean hydrocarbon reservoir can be used in various conventional in situ thermal recovery processes, such as SAGD, CSS, steam flooding, or a solvent-aided process (SAP). Selected embodiments herein may be applicable to an existing hydrocarbon recovery process, such as after the hydrocarbon production rate in the recovery process has peaked.
By way of example, a method disclosed herein may be standalone or may be used in combination with other enhancements to thermal technology. In one aspect, a method disclosed herein may be used in combination with a recovery process involving the use of steam and solvent, such as a "solvent-aided" process (SAP) wherein the volatile agent is co-injected with the steam and solvent. It is contemplated that the solvent added as part of SAP would cause the traditional solvent effects known to those in the art such as viscosity reduction, while the addition of the volatile agent, for example a volatile amine, would produce IFT reduction as well as TAN reduction. Together, the traditional SAP
process in combination with a method disclosed herein may yield synergistic incremental oil recovery (a reduction in residual oil in place) beyond the sum of each individual process when taken alone.
A recovery process involving the use of steam and solvent may also include other types of known processes where steam or solvent, or both ae selectively injected into the formation. For example, such processes may include a solvent-aided process where a relatively low amount of solvent (1-20 wt%) is co-injected with steam to facilitate removal or reduction of non-condensable gases (NCGs) accumulating at the steam chamber front.
By way of further example, a method disclosed herein may be used during conventional SAGD processes, wherein the volatile agent is co-injected with steam to enhance oil production. A typical SAGD process is disclosed in Canadian Patent No.
1,130,201 issued on 24 August 1982, in which two wells are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with an aqueous condensate. In this way, the injected steam initially mobilizes the in-place hydrocarbon to create a "steam chamber" in the reservoir around and above the horizontal injection well. The term "steam chamber" accordingly refers to the volume of the reservoir which is saturated with injected steam and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are recovered continuously through the production well. The conditions of steam injection and of hydrocarbon production may be modulated to control the growth of the steam chamber, to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.

The start-up stage of the SAGD process establishes thermal or hydraulic communication, or both, between the injection and production wells. At initial reservoir conditions, there is typically negligible fluid mobility between wells due to high bitumen viscosity. Communication is achieved when bitumen between the injector and producer is mobilized to allow for bitumen production. A conventional start-up process involves establishing inter-well communication by simultaneously circulating steam through each.
injector well and producer well. High-temperature steam flows through a tubing string that extends to the toe of each horizontal well. The steam condenses in the well, releasing heat and resulting in a liquid water phase which flows back up the casing-tubing annulus.
Alternative start-up techniques involve creating a high mobility inter-well path by the use of solvents or by application of pressures so as to dilate the reservoir sand matrix.
In the ramp-up stage of the SAGD process, after communication has been established between the injection and production wells during start-up (usually over a limited section of the well pair length), production begins from the production well.
Steam is continuously injected into the injection well (usually at constant pressure) while mobilized bitumen and water are continuously removed from the production well (usually at constant temperature). During this period the zone of communication between the wells is expanded axially along the full well pair length and the steam chamber grows vertically up to the top of the reservoir. The reservoir top may be a thick shale (overburden) or some lower permeability facies that causes the steam chamber to stop rising. When the inter-well region over the entire length of the well pair has been heated and the steam chamber that develops has reached the reservoir top, the bitumen production rate typically peaks and begins to decline while the steam injection rate reaches a maximum and levels off.
In conventional SAGD, after ramp-up, in an operational phase of production, the steam chamber has generally achieved full height (although it is typically still rising slowly through or spreading around lower permeability zones in some locations) and lateral or radial growth of the steam chamber along the longitudinal axis of the well pair becomes the dominant mechanism for recovering bitumen. Typically steam injection at the injector well is controlled so as to maintain a target steam chamber pressure during this phase.
According to embodiments herein, a method disclosed herein may be used to:
accelerate time to first oil production, reduce steam to oil ratio (SOR), reduce TAN, and/or reduce residual oil saturation, by co-injecting steam and at least one volatile agent.
Without limitation, in some embodiments, a method disclosed herein may help accelerating the production of hydrocarbons by producing incremental oil due to the reduction of capillary forces allowing the oil to flow more easily within the reservoir.
Without limitation, in some embodiments, a method disclosed herein may result in oil production rate acceleration. Without limitation, in some embodiments, a method disclosed herein may make it easier to reduce residual oil saturation, in essence increasing the recoverable oil in place and as a result decreasing the cumulative steam to oil ratios (CSOR or cSOR) by as much as 10-15%. The reduction in cSOR may have a corresponding effect of lowering the volume of greenhouse gas (GHG) emissions.
Without limitation, in some embodiments, a method disclosed herein may show a drop in the TAN of produced oil. It is contemplated that the generation of an in situ surfactant by a method described herein is a result of the reaction between the volatile agent, preferably a volatile amine, and organic acids present in the native hydrocarbons, which in turn reduces the TAN of the produced oil. Such a reduction in TAN not only assists oil production, but is also desirable for the reason that acidic hydrocarbon products having a high TAN can cause damage to production, transport, and processing equipment.
Often, hydrocarbons produced without TAN reduction may have a TAN as high as about 10-mg KOH/g in some parts of the world. For transportation and refinement, it is generally desirable to have a TAN less than about 1 mg KOH/g.
A suitable volatile agent may be selected to provide effective and efficient in situ formation of suitable surfactants which can reduce IFT between the bitumen (oil) and water (and optionally between oil and one or more of gas or formation rock), so as to reduce the viscosity (increase the mobility) of oil in the reservoir fluid for faster or increased flow rate and oil production, when compared to a typical thermal recovery processes where only steam is used, or where less effective surfactant precursors were used. Without limitation, it is contemplated that the volatile agent co-injected with steam may be selected based on the combination of the factors for selection discussed herein.
A suitable volatile agent may be a single volatile compound, for example a volatile amine, or a combination of volatile compounds. The term "volatile" as used.
herein refers to compounds having a higher volatility than water at like pressures and temperatures. In one aspect, it may be desirable that the volatile agent and steam can vaporize and condense under the same conditions, which allows the vapor of the volatile agent to initially rise up with the injected steam, penetrate the rock formation in the steam chamber, and then condense with the steam to form a part of the mobilized reservoir fluid.
In some embodiments, the volatile compound may comprise a volatile amine or combination of volatile amines, with the volatile amine(s) having a boiling point below the boiling point of water under steam injection conditions such that the volatile amine is sufficiently volatile to travel with (or ahead of) the injected steam in vapor form when penetrating the steam chamber, and then to condense at steam chamber front at a temperature below the boiling point of the volatile amine(s). At atmospheric conditions, the volatile amine may have a boiling point of less than about 100 C, such as 105 C. For example, where the volatile agent is n-propylamine, the boiling point of n-propylamine is about 47-49 C at atmospheric conditions. For example, where the volatile agent is n-butylamine, the boiling point of n-butylamine is about 75-77 C at atmospheric conditions.
It has been recognized that many polar compounds and aromatic compounds (e.g.
ammonia, alcohols, ketones) having a high solubility in water and very low solubility in oil, and/or, having a boiling point higher than that of water at like pressures. As such, these compounds are not suitable compounds for use as the volatile agent in an embodiment disclosed herein.
It is desirable that the selected volatile agent is a thermally stable compound in the presence of steam or hot water (i.e., capable of resisting decomposition at high temperatures).

In some embodiments, it is contemplated that the selected volatile agent may readily dissolve in oil. As such, it may be desirable that the volatile agent be selected to comprise at least both a basic component for reacting with the natural acids in the reservoir, and a hydrocarbon component for enabling the volatile agent to readily dissolve 5 into the in situ hydrocarbons. It is contemplated that such a reaction with the organic acids present in the reservoir reduces the TAN in the produced oil. For example, the volatile agent may be selected to comprise at least one basic component having an amino group (-NH,) and at least one hydrocarbon group.
Broadly understood, the term "amine" as used herein may refer to a single or a 10 combination of primary, secondary, and tertiary amines including, but not limited to, methyl amine, ethyl amine, propyl amine, butyl amine, di-methyl amine, allyl amine, di-ethyl amine, di-propyl amine, tri-methyl amine, or tri-ethyl amine, individually or together. As used herein, and unless otherwise specified or apparent in the context, propyl amine refers to n-propylamine (may be expressed as C,H5CH2NH2, C3H7NH.), or 15 C3H9N), and butyl amine refers to n-butylamine (may be expressed as CH3CH2CH2CH2NH2). Suitable amities for use in an embodiment disclosed herein may he selected from the broad class of amines in view of the selection considerations discussed herein.
A method for oil recovery from a subterranean reservoir may include the injection 20 of steam and a volatile agent via an injection well into the reservoir for mobilizing bitumen in the reservoir and the production of the fluid from the reservoir.
Reference will now be made in detail to certain embodiments of the disclosed methods examples of which are illustrated in part in the accompanying drawings and Examples below, which are provided for illustrative purposes intended for those skilled in the art and are not meant to be limiting in any way. For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
FIG. 1 schematically illustrates a typical SAGD arrangement 100 in a reservoir 112 of bituminous sands. The SAGD arrangement 100 includes a well pair, injection well 118 and production well 120. It can be understood that reservoir 112 is serviced by injection well 118 and production well 120, which mediates fluid communication between reservoir 112 and a surface completion.
In a typical SAGD operation, fluid communication between injection well 118 and production well 120 is established (known as the start-up stage) before normal oil production begins. During oil production, in cases where only steam is used, steam is injected into reservoir 112 through injection well 118. The injected steam heats up the reservoir formation, softens or mobilizes the bitumen in a region in the reservoir 112 and lowers bitumen viscosity such that the mobilized bitumen can flow. As heat is transferred to the bituminous sands, steam condenses and a fluid mixture containing aqueous condensate and mobilized bitumen (oil) forms. The fluid mixture drains downward due to gravity, and a porous region 130, referred to as the "steam chamber," is formed in reservoir 112.
In an embodiment as illustrated in FIGS. IA and 1B, a volatile agent 124 is co-injected with steam 116 into steam chamber 130 through injection well 118. The injected steam 116 mobilizes the bitumen in reservoir 112. As a result, a reservoir (formation) fluid 114 comprising oil 122 and condensed steam (water) is formed in steam chamber 130, largely at steam chamber front 132, and can drain downward toward the production well 120. In selected embodiments, the injected volatile agent 124 also travels mainly in vapor form towards the steam chamber front 132, and cools and condenses at or near the steam chamber front 132. At least a portion of the condensed volatile agent 124 may dissolve in the reservoir fluid 114, which may also assist in mobilizing the bitumen as will be further discussed below. Fluid 114 is drained by gravity along the edge of steam chamber 130 into production well 120 for recovery of oil 122, which contains various mobilized hydrocarbons.
As the volatile agent 124 cools near the steam chamber front 132 of steam chamber 130, it condenses and will react with some organic acids 126 such as carboxylic acids present in the region to form the desired surfactants 128. The surfactants 128 can assist mobilization of viscous hydrocarbons and with increasing the rate of oil phase flow through the formation towards the production well 120.

A suitable volatile agent 124 should be sufficiently volatile so that the volatile agent can be vaporized by heating (by steam) under reservoir operating conditions and the volatile agent vapor can ascend within the steam chamber 130. The volatile agent 124 may be a vapor prior to mixing with steam 116; alternatively the volatile agent 124 may be a liquid that is vaporized upon mixing with steam 116. Given that the volatile agent 124 is more volatile than water, it travels at the front of, or with, the steam front. Upon rising within the steam chamber 130, the volatile agent 124 interacts with the residual oil in place in the reservoir at the steam front. When interacting with the oil, the volatile agent 124 may cool and condense. A suitable volatile agent 124 also has a low enough volatility at lower temperatures, such as below about 20 C to 50 C depending on the particular thermal recovery process, that the volatile agent 124 becomes condensable when travelling to a lower temperature zone in the reservoir, particularly the steam chamber front 132. The condensed volatile agent 124 should be sufficiently reactive with acids 126 present in the reservoir to form desired surfactants 128, and may be miscible with oil or bitumen or sufficiently soluble in oil and less soluble in water.
The volatile agent 124 is sufficiently volatile to rise up with the injected steam in vapor form when penetrating the steam chamber, and can then condense at the steam chamber front 132 of the steam chamber 130.
For example, the steam chamber front 132 is typically at a lower temperature, such as from about 12 C to 150 C, as compared to the temperature at the center of the steam chamber or near the injection well, which may be at 170 C, or 225 C, or higher.
The condensed volatile agent 124 may be soluble in or miscible with the hydrocarbons in the reservoir fluid 114, so as to increase the drainage rate of the hydrocarbons in the fluid through the reservoir formation.
It is contemplated that a suitable volatile agent should be sufficiently soluble in both oleic and aqueous phases. Solubility in the aqueous phase assists the volatile agent.
to travel with steam to the steam front, wherein the steam acts as a carrier.
Solubility in the oleic phase facilitates the efficiency of reaction between the amine and the bitumen, which leads to in situ surfactant generation. In one embodiment, Liquid ¨
Liquid Equilibrium modelling indicates that the selected volatile agent, for example a volatile amine, should be more soluble in oil than water, for example, K oleic/aqueous should be greater than or equal to 2.0 (see Equation 1 below).
K Qµeic Xoleic = Yoleic ¨ (,?_' 2.0) (1) aqu,oõs xaqueous Yaqueous As the temperature increases, the volatile agent 124 generally prefers to be in aqueous phase. For example, at the injection point the volatile agent 124 would dissolve with steam 116 and travel to the steam front. As the volatile agent 124 moves away from the injector well towards the steam chamber front, the temperature decreases and the volatile agent 124 generally begins to prefer the oleic over the aqueous phase. Thus, the solubility of the volatile agent 124 in the oleic phase improves as the temperature decreases when the volatile agent moves away from the injector well. It has been recognized that volatile agents selected with this characteristic ability, e.g., propyl amine or butyl amine, can result in an increased efficiency of the reaction of the volatile agent with acids in the oil phase or around the oil phase, which in turn results in a greater amount of in situ surfactant generation, as compared to other volatile surfactant precursors that have vapor pressure profiles that are very different from, for example, water, propyl amine or butyl amine. The increased surfactant generation in turn leads to a lower IFi between oil and water and the formation of oil-in-water emulsion and thus improved oil recovery.
As is known to those skilled in the art, with a gravity-dominated process, such as SAGD, a start-up process is required to establish communication between the injector and producer wells. A skilled person is aware of various techniques for start-up processes.
such as for example hot fluid wellbore circulation, the use of selected solvents such as xylene (as for example described in CA 2,698,898 to Pugh, et al.), the application of geomechanical techniques such as dilation (as for example described in CA

2,757,125 to Abbate, et al.), the use of surfactants (as for example described in CA
2,886,934 to Zeidani), or the use of one or more microorganisms to increase overall fluid mobility in a near-wellbore region in an oil sands reservoir (as for example in CA 2,831,928 to Bracho Dominguez, etal.). It is contemplated that the volatile agent 124 may be added during a start-up process, particularly during circulation. The volatile agent 124 may aid the penetration of steam 116 into the formation, thereby improving heat transfer.
Btillheading is an alternative start up technique known to those skilled in the art .. that can be used when the initial reservoir conditions are such that formation water is mobile near the injector wellhead. As steam is injected through the injection well 118 the steam condenses (to hot water). As more steam is injected, the condensed hot water travels radially outward from the wellbore heating the near-wellbore and inter-well region as shown (with arrows) in FIG.'1B. Bullheading is generally known to be more thermally efficient than circulation because the majority of the injected heat from the steam ends up in the reservoir; there is no recycle. Practically, in the case of the injection well 118, no recompletion is typically needed following bullheading (although it may be done in some cases). Where bullheading is utilized, the bottom hole pressure should be monitored so as not to exceed a maximum reservoir operating pressure as there is no production of the injected fluids.
Bullheading in a reservoir with heterogeneities, particularly where these heterogeneities are severe, can lead to uneven heating along the injection and production wells, poor steam chamber development and conformance, as well as a higher SOR. It is contemplated that the use of a method disclosed herein, namely the addition of a volatile agent to the injected steam during bullheading, may have several advantages.
In one aspect, the volatile agent, for example a volatile amine, may react with the residual oil in place to fon-n in situ surfactant(s) as discussed herein. This reaction may reduce the oil saturation in the affected area within the reservoir to a greater degree than if no volatile agent was present during bullheading, allowing a larger volume of steam to be injected, and in particular, injecting a larger volume of steam at an increased rate of injection.
In another aspect, the volatile agent, for example a volatile amine, may react with the residual oil in place to form in situ surfactant(s) as discussed herein.
This reaction may increase the oil relative permeability resulting in an improved flowability of the bitumen.

In a further aspect, the volatile agent, for example a volatile amine, may react with the residual oil in place to form in situ surfactant(s) that may in turn mobilize bitumen that serves to increase the initial well production rate and improve SOR.
As is typical, the injection and production wells (118, 120) may have terminal 5 sections that are substantially horizontal and substantially parallel to one another. A
person of skill in the art will appreciate that while there may be some variation in the vertical or lateral trajectory of' the injection or production wells, causing increased or decreased separation between the wells, such wells for the purpose of this application will still be considered substantially horizontal and substantially parallel to one another.
10 Spacing, both vertical and lateral, between injectors and producers may be optimized for establishing start-up or based on reservoir conditions.
At the point of injection into the formation, or in the injection well 118, the injected steam may be at a temperature from about 152 C to about 286 C or about 328 C, and at a pressure from about 0.5 MPa to about 12.5 MPa. These conditions may be 15 collectively referred to as steam injection conditions. A person skilled in the art will appreciate that steam injection conditions may vary in different embodiments depending on, for example, the type of hydrocarbon recovery process implemented (e.g., SAGD, CSS) or the volatile agent selected.
However, once the steam enters the reservoir, its temperature and pressure may 20 drop under the reservoir conditions. The reservoir temperature will become colder in regions further away from injection well 118. Typically, during SAGO
operations, the reservoir conditions may vary. For example, the reservoir temperatures can vary from about 10 C to about 235 C, or up to 328 C, and the reservoir pressures can vary from about 0.6 MPa to about 3 MPa, or up to 12.5 MPa, depending on the stage of operation.
25 The reservoir conditions may vary in different embodiments.
The timing for commencing co-injection of the volatile agent .124 may depend on various factors and considerations. It is contemplated that co-injection of the volatile agent .124 can start immediately after communication is established between the injection and production wells (118, 120). For example, volatile agent 124 injection can be initiated after circulation start-up or .bullheading ends and prior to or concurrent with the start of SAGD ramp-up. Without being bound to a particular theory, it is contemplated that beginning the co-injection of a volatile agent(s) concurrent with SAGD
ramp-up may enable the volatile agent to react with the residual oil in place either prior to or concurrent with the exposure of the residual oil to steam, although in different embodiments injection of the volatile agent may be subsequent to a period of initial steam injection or even oil production.
Referring to FIG. I B, the central region of the steam chamber 130 (or porous region) is efficiently cleaned of residual oil through the early injection of the volatile agent 124 with the steam 11.6, resulting in a very low residual oil saturation in this region.
The ability of the volatile agent .124 to react with the residual oil in place allows the volatile agent 124 to dissolve into the oil or residual oil in place early on, as opposed to dissolving into the oil 122 that has already been heated and mobilized by the steam prior to any exposure to the volatile agent. In other words, the oil is being reacted all the way down to the residual oil saturation more quickly. The volatile agent 124 can travel to the cold steam chamber front in a bituminous sands reservoir 112 with minimal reaction with the residual oil in the steam chamber 130 due to a very low residual oil saturation from early cleaning. The minimal reaction between a very low residual oil saturation and volatile agent 124 in the steam chamber 130 is thought to result in a very efficient process, for example by lowering the volatile agent consumption in the mature steam chamber 130. Furthermore, in one aspect it is contemplated the residual oil saturation when co-injecting a volatile agent 124 with steam is expected to be less than that of a traditional SAGD process. Thus, it is contemplated that starting the co-injection of the volatile agent 124 with steam 116 early in the SAGD lifecycle, for example, after start-up, is beneficial.
Conversely, if the volatile agent is added later in the SAGD lifecycle, for example 1 to 2 years after starting steam injection, the volatile agent first travels through the steam chamber that has been developed in order to reach the cold bitumen wall, where it is desired for the volatile agent to react with the cold bitumen. It is possible that, as the volatile agent is travelling through the developed steam chamber, the volatile agent even in vapor phase may be reacting with residual oil that was left behind as the steam chamber front progressed through the formation. This residual oil may be further mobilized by the volatile agent, but may not drain effectively to the production well because it is not at the edge of the steam chamber where pressure gradients are favourable for gravity drainage. When the volatile agent reacts with the colder bitumen at the steam chamber front, the drainage of the produced fluid to the production well is more efficient.
It has been recognized that by adding a volatile agent to the steam earlier in the SAGD
process, as described above, the residual oil in the reservoir may be produced more quickly and efficiently. Not only may a greater portion of the oil in place be produced when compared to conventional SAGD with steam injection alone, but oil production may also be accelerated by co-injecting the selected volatile agent.
In some embodiments, after the fluid 114 is removed from the reservoir, steam 116, and optionally any condensed (hut unreacted) volatile agent, may be separated from oil in the produced fluids by a method known in the art depending on the particular volatile agent(s) used. The separated steam and volatile agent can be further processed by known methods, and recycled to the injection well 118.
In some embodiments, produced volatile agent may be separated from the produced water before further treatment, re-injection into the reservoir, or disposal of the produced water, the produced volatile agent, or both. In some embodiments, ease of handling and recovery in the liquid phase at surface conditions may be a consideration for selecting a suitable volatile agent. In an alternative embodiment, the volatile agent may remain with the produced fluids.
In various embodiments, the co-injection of a volatile agent may include a selected injection pattern. For example, the co-injection pattern may include simultaneous injection with the steam, alternative injection of steam and a volatile agent at different times (in which case, the volatile agent may be separately heated), staged (e.g., sequential) injection at selected time intervals, or injection at selected locations within the SAGD operation (e.g., across multiple well pairs in a SAGD well pad). The co-injection may be performed in various regions of a well pad, or at multiple well pads to create a target injection pattern to achieve target results at a particular location of the pad or pads.
In various embodiments, the co-injection may be continuous or periodic. The co-injection may be performed through an injection well (e.g., injection well 118), and may involve injection at various intervals along a length of the well.
The volatile agent should be suitable for use under SAGD operating conditions, which include certain temperatures, pressures and chemical environments. For example, in various embodiments, the volatile agent may be selected such that it is thermally stable under the reservoir conditions and the steam injection conditions and therefore can remain effective after being injected into the steam chamber. In other words, in some embodiments, it may be beneficial that a selected volatile agent is thermally stable until it reacts with the organic acid in the formation.
While some examples herein are discussed with regard to SAGD Operations, as above, it can be appreciated that a volatile agent may be similarly used in other steam-assisted recovery processes, such as CSS. In a CSS operation, a single well may be used to alternately inject steam into the reservoir and produce the fluid from the reservoir. The single well may have a substantially horizontal or vertical section in fluid communication with the reservoir. The single well may be used in a cyclic steam recovery process. With the use of the single well for injection and production, a temperature in the reservoir may be about 234 C to about 328 C and a pressure in the reservoir may be from about 0.5 MPa or about 3.0 MPa to about 12.5 MPa.
In embodiments of the present disclosure, a single well may be used to form and expand the steam chamber and to produce oil. In such an embodiment, and in other embodiments where multiple wells are used, a single well may be configured for injection and may be configured for production. The well may be reconfigurable repeatedly. to be used as an injection well and a production well. The well(s) used in embodiments of the present disclosure may include horizontal wells, vertical wells, or directional wells (drilled by directional drilling), or a combination thereof.
Therefore, it.
should be understood that a well is configurable for injection or production if the well can be alternatively configured to function as an injection well, or as a production well. In some cases, a well may be completed for only injection, and another well may be completed for only production. In some embodiments, a well may have a first section completed for injection and a second section completed for production. In different well arrangements, three or more wells may be used to service one reservoir formation, and may be in fluid communication with the same steam chamber.
Generally, an embodiment disclosed herein can be used during any in situ thermal recovery processes where steam is injected into a reservoir to mobilize or liquefy the native bitumen therein to form a fluid containing hydrocarbons and water (condensed steam) that can be produced from the reservoir, where the reservoir also contains suitable acids that can react with the selected amines to form surfactants.
It is contemplated that steam may be co-injected with a specifically selected volatile agent, such as a selected volatile amine. The volatile agent co-injection phase of the recovery process may include the co-injection of saturated steam and between about 10 ppm to about 10,000 ppm of volatile agent (injection mixture). While a smaller amount of the volatile agent can also help, to achieve optimal performance with a view to balance production improvement and resource and operation cost, a sufficient amount of the volatile agent should be injected to more fully utilize the organic acids present in the formation. To achieve this target, about 1,000 ppm to about 2,000 ppm (or about 0.1 wt%
to about 0.2 wt%) of the selected volatile agent in the injection mixture may be needed in some embodiments. The operation performance may be measured in part by the TAN

reduction in the produced fluid as discussed elsewhere herein. For example, the injection mixture or fluid may include about 99.8 wt% of steam and about 0.2 wt% of the volatile agent. The concentration of the volatile agent in different embodiments may be relatively lower and may vary throughout the course of the well life and the production process.
However, based on test data available, it has been found that for at least some bitumen reservoirs, an amine concentration of 500 ppm or lower would not provide optimal utilization of the acid content available in the reservoir.
Injection pressure of the injection fluid may be about 2 MPa to about 4 MPa.
In some embodiments, the injection pressure may be up to about 7 MPa to 8 MPa.
Steam saturation temperature may be about 214 C to about 252 C. Before mixing with the steam or otherwise heating the volatile agent, it may be stored or transported at room temperature. For example, propyl amine or butyl amine may be cold or at ambient temperature during storage and transportation. In other embodiments, the volatile amine may be pre-heated to a vapor form before injection. The volatile agent may be injected with a steam stream at the well head, where injection is controlled to maintain a target steam chamber pressure. In sonic embodiments, the withdrawal rate from the lower production well may be controlled based on a predetermined target production 5 temperature.
Volatile amine injection may occur over a period of about 9 to 24 months during the hydrocarbon recovery process or may occur over longer or shorter periods depending on the reservoir, the point in the process at which the amine is injected (e.g., after start-up), or the particular in situ hydrocarbon recovery process being performed.
Steam 10 injection rates may be from about 175 t/d to about 450 t/d. Volatile amine injection rates may be from about 3.5 t/d to about 6 tic!. An increase in steam rates may be observed to replace the additional voidage created by incremental production due to volatile amine injection. Overall, volatile amine injection may offer a production acceleration technology resulting in reduction of steam usage over the life of a hydrocarbon recovery 15 operation. Volatile amine injection rate may be regulated to the steam injection rate.
The volatile amine may be injected into the steam header or downstream of a steam control valve on a well. Providing a selected concentration of a volatile amine to the reservoir may involve injection of the selected concentration directly or may involve increasing the concentration over time to reach the selected concentration.
For example, a 20 volatile amine may be co-injected with steam at a selected concentration of 2,000 ppm (0.2 wt%). In an alternative example, a volatile amine may be co-injected with steam at a first concentration of 500 ppm (0.05 wt%), a second concentration of 1,000 ppm (0.1 wt%), a third concentration of 1,500 ppm (0.15 wt%), and a selected concentration of 2,000 ppm (0.2 wt%), with each increase in concentration occurring when operations are 25 deemed steady. Deeming operations steady may occur based on, for example, monitoring reservoir pressure, injection pressure, pump performance, oil production rate, steam to oil ratio (SOR) or other operational responses. Monitoring drawdown (which is a proxy for scale formation) may provide another performance indicator. Such a staged increase from 500 ppm to 2,000 ppm may occur over a period of 30 days, or over a shorter or longer 30 .. period. Such a staged increase may occur with fewer or additional stepped or more gradual changes in volatile amine concentration. The concentration of volatile amine may be reduced for various reasons during a hydrocarbon recovery process, for example, from 2,000 ppm to 1,000 ppm, if accelerated oil production has been observed and a lower concentration of volatile amine may be suitable for maintaining oil production at the accelerated oil production rate.
Without any limitation to the foregoing, certain aspects and selected embodiments of the present disclosure are further described or illustrated by way of the following examples.
EXAMPLES
For the tests discussed in Example 1 below, the volatile agent was co-injected with saturated steam into a sample core at a concentration of 0 to about 1 wt%
(or 0 to 10,000 ppm by weight). Injection pressure of the injection fluid was 2.4 MPa to 2.6 MPa.
Steam saturation temperature was about 220 C to 230 C. The tested compounds included example volatile agents and comparative agents as described below.
The system used in the tests is illustrated in FIG. 2. It included a pressure vessel 200. A sample core 202 saturated with bitumen was suspended in the vessel 200, above a collection tube with a funnel 204. The vessel was fitted with band heaters 206, which were controlled by a control system 208. The vessel 200 was insulated with an insulation blanket 210. Pressure sensor 212 and temperature sensors 214 were provided Ibr measuring and controlling the pressure and temperatures in the vessel 200 and in the sample core 202. When steam and an example volatile agent were injected, mobilized oil and condensed fluids were drained and collected at the bottom of the vessel 200 through funnel 204.
Example 1 ¨ Steam Soak Tests Having regard to FIG. 2, an experimental steam soak test was performed in a pressure vessel 200 (T = 220 C ¨ 230 C and P -= 2.4 ¨ 2.6 MPa) to, among other things, mimic gravity drainage, measure amine volatility, measure amine solubility in oil, indirectly measure IFT, and reduction in TAN, thereby demonstrating incremental recovery of hydrocarbons over steam alone.
The test was set up with an oil saturated core 202 (i.e. dead oil with no solution gas present), positioned within the pressure vessel 200, having an initial water saturation (S,,) of 20% and oil saturation (S.) of 80%. The core 202 was hung in the pressure vessel 200. The vessel 200 was gradually heated such that the water along with the volatile amine evaporated and contacted the bitumen, causing the bitumen to drain into the funnel 204. The soak test performance was then evaluated by weighing the amount of oil recovered and basic sediment and water (BS&W) was measured. Because the original-oil-in-place (00IP) was known, the recovery factor was deduced using collected emulsion and BS&W. The present example was a batch process (i.e. not a continuous process), whereby all the produced bitumen was collected when the heat supply had been ceased. The TAN reduction in the core was also estimated by measuring the TAN
in the drained fluid.
The results of representative samples are shown in TABLE I, where a fixed volatile agent concentration of 2,000 ppm was used. Test results are also shown in the figures and other tables with results of different tested compounds as described below.
TABLE I. Results of Steam Soak Tests with Propyl Amine (Example 1) Initial Produced Avg. 00IP
Concentration Model ph Saturation Oil Oil Test Inside Recover y Pressure CSOR
BS&W (kPa) ppm (g) % T ("C) Condensate ( Steam alone NA 130 12.6 222.3 5.9 21.68 2423.06 2.15 Propylamine 20(8) 131 17.8 226.1 9.2 59.42 2602.34 0,85 Compound - C 2000 130 7.6 224.2 6,3 28.75 2511.47 (.74 Compound - I) 2000 129 16.7 220.9 9,3 23.24 2359.48 2.03 Compound - F. 2000 129 17.9 221,8 8.6 26.53 2400.21 1.82 Five steam soak experiments were performed using the following: a) steam alone (baseline), b) propylamine (supplied by Sigma Aldrich), c) Compound C - a proprietary ketone compound (provided by the Saskatchewan Research Council supplied by Sigma Aldrich), d) Compound D ¨ a mixture of an inorganic base and a heavier primary amine (Baker Hughes SAW 8374), and e) Compound E - a proprietary mixture of a proprietary aqueous diamine with stabilization (provided by NACHURS ALPINE SOLUTIONS
Industrial). As shown in TABLE I, it was observed that propyl amine provided a >100%
increase in oil production (from 22.68% to 59.42%) and a 60% reduction in CSOR
(from 2.15 to 0.85) when compared to steam alone. Furthermore, it was observed that propyl amine demonstrated significantly greater oil recovery when compared to the other volatile agents tested. Looking at compounds C-E, it is notable that at like saturation pressures, none of the compounds were able to demonstrate a significant decrease in CSOR or a significant increase in original oil in place (00IP) recovery when compared to steam injection alone. Notably, each of compounds C-E have boiling points to the right of the water vapor pressure curve indicating that their respective boiling points are greater than that of water at like pressures. As a result, in a reservoir system, compounds C, D and E are less volatile than water and would likely not move with the steam front, instead likely remaining near the injector wellbore.
Of note, it was observed that propyl amine also demonstrated about a 70%
reduction in TAN. The original TAN of the sample was 1.3 and the resultant TAN
after reacting with propyl amine was 0.3. These test results demonstrated that propyl amine generates both in situ suifactant-like and solvent-like effects. Of note, the overall bitumen recovery from propyl amine was over 59%. The results suggest that where the volatile agent is propyl amine, the recovery of hydrocarbons produced was more than double when compared to steam alone.
Similar tests were conducted with other sample volatile agents and comparison compounds, including butylamine, di-ethylamine, di-methylamine, tri-methylarnine, di-propylamine and others, at a constant pressure of 2.5 MPa with a temperature gradient.

Results from these tests are summarized in TABLES II, Ill, and IV, and shown in FIGS.
3A, 3B, 3C, 313, 3E, 3F, 3G and 3H. It was found that n-butylamine performed similarly to n-propylamine, and both n-butylamine and n-propylamine performed much better than the other tested volatile agents and comparison compounds. In TABLE II, Compound F is a proprietary mixture including n-butylamine (provided by NACHU.RS ALPINE
SOLUTIONS Industrial), Compound G is a benzenesulfonate surfactant (provided by Weatherford), and Compound H is a proprietary mixture including a proprietary aqueous amide (provided by NACHURS ALPINE SOLUTIONS Industrial). Initial TAN was about 1.75 to about 1.80. Although for Compound G it appears that TAN
increased by

3%, this is within the range of error and suggests that TAN was not reduced under the conditions of the testing.

TABLE II. Summary of Results for Steam Soak Tests Post Test Bitumen Test Concentration Extracted Resultant TAN
Recovery Compound (%) Oil (g) TAN Reduction Factor ( %) (%) Deionized water -- 4.37 1.75 0 32.37 , Deionized water -- 3.66 1.75 0 25.78 Deionized water , -- , 5.78 , 1.75 0 21.35 Propylaminc , 0.2 4.96 1.10 37 26.58 Propylamine 0.2 7,44 1.25 29 39.73 Propylamine 0.2 5.54 1.13 35 30.13 Propylannne 0.5 7.21 0.65 63 39.59 Propy1amine 1.0 9.24 0.00 100 49.75 Propylamine 1.0 9.06 0.00 100 49.05 Butylamine 0.05 5.58 1.70 3 31.02 Butylamine 0.1 6.03 1.4 20 33.81 Butylamine 0.2 7.98 0.73 58 43.39 Butylamine 0.2 , 6.09 0.95 46 35.75 Butylamine 0.3 6.84 0.95 46 35.75 Butylamine , 0.5 , 10.89 0.8 54 , 57.93 Butylamine 0.5 , 9.44 0.8 54 50.62 Butylarnine 1.0 9.41 0.08 95 50.92 Diethylamine 0.2 3.09 1.5 14 16.84 Dimethylamine 0.2 3.28 1.4 20 18.03 Trimethylantine 0.2 2.98 1.65 6 16.04 Dipropylamine 0.2 5.67 , 1.30 , 26 30.73 Compound F 0.4 4.19 1.70 3 22.88 Compound 0 . 0.2 6.35 1.80 -3 34.37 Compound H 0.2 6.27 1.75 0 33.00 Test results for reduction in TAN by injection of propyl amine or butyl amine are 5 also summarized in TABLES III and IV, respectively (also see FIGS. 3F and 3H). The results of TAN reduction shown in FIG. 3B are percentages based on the values listed in TABLES HI and IV. That is, the data points represent [TAN (before) - TAN
(after)1/TAN (before). The tests provided evidence that a representative injection mixture of steam and volatile amine can reduce TAN in a representative oil saturated core. A
10 person of skill in the art will appreciate that the results obtained in the tests are within a range of experimental error. During each test, there was a limited amount of oil available to react with the amine, whereas in the reservoir, the amount of amine injected will be the limiting factor in terms of in situ surfactant generation. A person of skill in the art will appreciate that the 96 TAN reduction observed in the tests may or may not be more pronounced than under reservoir conditions. It will also be appreciated by a person of skill in the art that in contrast to a controlled test environment, results may vary depending on the properties of the hydrocarbon reservoir selected or as a result of hydrocarbon recovery operational procedures not simulated in the tests.

TABLE III. Test Results for TAN Reduction with n-Propylamine 0.2% Propy [amine 0.2% Propylarnine 0.2% Propylamine Solution (Trial 1 of 3) (Trial 2 of 3) (Trial 3 of 3) Before After Before After Before After , Aqueous 11.57 8.37 11.57 7.50 11.57 7.90 TAN 1.75 1.1 1.75 1.25 , 1.75 1.13 0.5% Propylamine 1.% Propylarnine (Trial 1% Propylamine Solution (Trial 1 of 1) 1 of 2) (Trial 2 of 2) Before After Before After Before After Aqueous 11.83 9,99 11.99 10.60 11.99 10.9 pH
TAN 1.75 0.65 ' 1.75 0.0 1.75 0.0 TABLE IV. Test Results for TAN Reduction with n-Butylamine 0.01% .Butylarnine 0.1% Butylamine 0.2% Butylamine Solution (Trial 1 of 1) (Trial 1 of 1) (Trial 1 of 2) Before , After Before After Before After Aqueous 11.32 6.7 11.47 7.2 11.26 8,20 pH
TAN 1.8 1.70 1.75 1.4 1.75 0.73 0.2% Butylamine (Trial 0.3% Butylamine 0.5%
Butylamine Solution 2 of 2) (Trial 1 of 1) (Trial 1 of 2) Before After Before After Before After Aqueous 11.38 7.8 11.76 9.00 11.94 9.2 pH
TAN 1.75 0.95 1.8 0.65 1.75 0.8 0.5% Butylamine (Trial 1% Butylamine (Trial Solution 2 of 2) 1 of 1) _ Before After Before After Aqueous 11.84 9.10 12.02 10.9 pH
TAN 1,80 0.80 1.8 0.08 Example 2 - Vapor Pressure and Solubility Analysis A study of amine vapor pressure curves in comparison to that of water was conducted using UniSim, a commercially available compositional process simulator. A
Non-Random Two Liquids Model (N.RTL) equation of state was used for modeling the vapor pressure and solubility curves shown in FIGS. 4, 5A, 5B and 5C. Each of FIGS.
5A, 5B and 5C was generated assuming a reservoir pressure of 2.5 .MPa.
FIGS. 6 and 7 show the solubility of the binary mixture in a gas-oleic and a gas-aqueous system respectively, and illustrate the volume of volatile agent, for example, volatile amine, that would dissolve in the oleic phase (FIG. 6) and in the aqueous phase (FIG. 7) prior to the onset of a vapor phase. K values (1/solubility) are shown in oleic and aqueous phases, respectively, for volatile amines (e.g., Cl ¨ C6) at various pressures.
It was observed that the K values for amines (from Cl to C6) decrease, suggesting that solubility in the oleic phase increases as the overall volatility decreases.
Without being limited to theory, as shown in FIG. 7, one possible mechanism to improve oil mobility is that the volatile agent, in this case the volatile amine, can partition into both the oleic and aqueous phases, with the majority being in the oleic phase, providing a surfactant-like effect. In some embodiments, the basic nature of the amine group of the volatile amine reacts with the organic acids (e.g. naphthenic acid) present in hydrocarbons, lowering the oil-water interfacial tension (71-'1) and improving oil mobility.
As such, the volatile amine may be selected to have a pH sufficient to react with the natural acids in the range of about 8 to 14, preferably about 8 to 11.
Having further regard to FIG. 7, a further possible mechanism is that the volatile amine can act as a solvent due to its solubility in oil and water, providing a solvent-like effect including the elongation of oil droplets (discussed further in Example 3).
Example 3 ¨ Mechanism of Action FIGS. 8 and 9 illustrate the contemplated mechanism of action of the interaction of the volatile agent in a reservoir. FIG. 8 provides a hypothetical example of a process flow S800 for co-injecting a volatile agent and steam. FIG. 9 provides a schematic of the process flow of FIG. 8 in reservoir formation 130 as illustrated in FIG. 1. It is contemplated that at S802, injected steam 116 and volatile agent 124 enter the steam chamber 130 in vapor form and travel towards the steam chamber front 132. At the steam chamber front 132, both steam 116 and the volatile agent 124 condense into the liquid form. While only one region of steam and the volatile agent vapor is shown, it can be appreciated that the pores in the formation (blank space in FIG. 9) may be filled with vapors of steam and the volatile agent or their condensed liquid form. At S804, the volatile agent 124 dissolves into the oil 122 in place. At S806, the condensed volatile agent 124 reacts with organic acids 126, such as naphthenic acids, which may include cyclopentyl- or cyclohexyl carboxylic acids, in the bitumen formation to form one or more surfactants 128 at S808. As illustrated, organic acid 1.26 is depicted as present in the oil phase but it .may also be present in other phases in the pores of the formation. The formed surfactant(s) 128 can reduce the interfacial tension between oil and water, and optionally between oil and formation rock 904. In this regard, volatile agents generally having a high pH can react with organic acids present in the oil in place. In situ surfactants 128 formed at S808 can reduce the WI' between oil and water in the formation fluid and IFT between oil or formation fluid and the formation rock 904. As a result, oil and the formation fluid become mobile or more mobile. For example, due to the surfactant present at the interface of oil and water (or at the interface of an oil phase and an aqueous phase), elongation of oil droplets 122 may. occur at S810 as a result of the lower IFT, enabling the oil to flow through small pore throats or between formation rocks 904 instead of otherwise being trapped by capillary pressure. The elongated droplets of oil 122 can then drain or be driven through the small pore throats and flow downward under gravity drainage toward the production well to be produced at S812. Any unreacted condensed amine may also act as a solvent, which may also facilitate movement of oil towards the production well 120. The combined solvent-like and surfactant-like effects may combine to synergistically increase the mobility and flow rate of the hydrocarbons, improving oil production.
Another possible mechanism for improved production rate is the oil-water emulsion in the formation fluid 114 may invert from water-in-oil to oil-in-water emulsion depending on the water and oil proportions in the fluid.
Reducing 'Fr between oil and rock and inversion of water-in-oil to oil-in-water emulsion can each be considered to increase the apparent permeability of the formation, thus allowing faster drainage of the formation fluid, particularly oil phase therein, and hence a higher rate of oil production.

Example 4 ¨ Testing the Effect of Amine on .Demulsification of Produced Emulsion An emulsion stability laboratory test was performed on produced emulsion from a 5 SAGD operation in the Athabasca oil sands in Northern Alberta, Canada.
Stable emulsion was added to four 100 mL standard centrifuge tubes (A, B, C & D). The volume of emulsion in each tube was recorded, and the tubes were placed in a water bath at 40 "C
for 60 minutes before 200 ppm Tretoliteml DM08663X demulsifier (DMO, available from Baker Hughes) was added to the emulsion in tube B, 1% n-butylamine (based on the 10 total amount of emulsion or entrained water present) was added to tube C, and both 200 ppm DMO and 1% n-butylamine were added to tube D. The tubes were agitated by inverting each tube 20 times and placing the tubes back in the water bath at 60 C. The amount of water separated from each tube was measured at time intervals of 30 min, 1 h, 2 h, and 4 h. After the last time interval, all tubes were centrifuged at a temperature of 15 60 C for 30 .minutes and the final amount of water was measured.
Efficiency is reported by comparing the amount of water removed under the conditions of this test to the total amount of water present in the oil continuous phase emulsion as previously measured by basic sediment & water (BS&W) testing.
Results are shown in TABLE V below and illustrate that demulsification was most efficient (24%) 20 when n-butylamine was combined with DMO. Under the laboratory conditions tested, the addition of n-butylamine did not have a detrimental effect on the demulsifying chemistry.
From these test results, it could be expected that addition of n-butylamine, or similarly structured amines such as n-propylamine, would also have no or little detrimental effect on the demulsifying chemistries of produced fluids in other similar oil recovery 25 operations.

TABLE V. Summary of Emulsion Stability Test Results Sample 30 min 1 hour 2 hour 4 hour Efficiency No water No water Minor water A - neat emulsion 3.0 ml 10.2 visible visible coalescence B - emulsion with 0.50 ml 0.60 ml 1.40 ml 5.0 ml 16.8 200 ppm DMO
C - emulsion with 0.05 ml 0.05 ml 0.05 ml 0.30 ml --1.2 1% n-butylamine D - emulsion with n-butylamine 5.0 ml 6.0 ml 6.5 ml 7.0 ml 24.0 & 200 ppm DMO
Example 5 ¨ Static Adsorption Tests A static adsorption tube was used including an inner top insertion tube having a screen at each end, and an inner bottom insertion tube. Clean Ottawa sand was loaded into the top insertion tube and sealed by the screen (mesh) on both ends. The tube was transferred into and kept overnight in a glove box having an N, atmosphere. In the glove box, dissolved 02 was removed from deionized water and the water was used to prepare a butylamine stock solution with a concentration of 0.2%. The prepared solution was loaded into the bottom insertion tube, which was placed in the lower part of the static adsorption tube. The top insertion tube containing the sand was placed on top of the bottom insertion tube within the static adsorption tube and the static adsorption tube was sealed with a top cap. A second sample was prepared in the same manner along with a reference tube without sand.
The three tubes were removed from the glove box and mounted in an oven, ensuring the top insertion tube containing the sand was always above the amine solution and did not contact the solution in the bottom insertion tube. The oven was heated to 220 C, at which point the tubes were rotated for 72 hours to expose the sand to the amine solution at a temperature representative of reservoir conditions in the presence of steam.
After 72 hours, with the top insertion tube above the bottom insertion tube, liquid was allowed to drain into the bottom insertion tube. After allowing the tubes to cool, the amine concentration in the drained solution was measured to calculate how much amine had been adsorbed by the sand. Test results are shown in TABLE VI. Results indicated that clean Ottawa sand adsorbed very little amine, with amine losses from the solution of 3.1% and 4.5% respectively for the two sand trials. For the sample sand at the conditions of this test, most of the amine was available to act on the oil in the sand and was not retained by the sand.
TABLE VI. Results of Static Adsorption Tests Ottawa Sand Ottawa Sand Reference (Trial 1 of 2) (Trial 2 of 2) Sand (g) no sand 6.08 6.052 0.2% Butylamine Solution (g) 14.05 14.02 14.01 Tube weight before test (g) 288.59 335.45 334.79 Tube weight after test (g) 288.58 335.44 334,78 Weight loss (g) 0.01 0.01 0.01 pH 11.49 11.11 11.18 Amine concentration (Ing/L) 1799 1775 1750 Stock solution concentration (mg/L) 1832 1832 1832 Total amine added (ing) /5.7 25.7 /5.7 Amine left in solution (mg) 25.3 24.9 24.5 Amine lost (mg) 0.5 0.8 1.1 Amine lost (%) 1.8 3.1 45 Amine adsorption on sand NA 13,2 18.9 (mg/I 00 g sand) Example 6. Forecast of Acceleration of Oil Production Rate Performance forecast was performed to estimate recovery process progress with or without co-injection of a selected amine for two years after initial production of oil.
Representative results of steam injection rates and oil production rates, and the instantaneous steam to oil ratio (ISOR or iSOR) for a SAGD well pair are shown in FIGS. 10 and 11, respectively.
As can be seen from these results, as compared to SAGD operation with pure steam injection (lines indicated as "SAGD" in FIGS. 10 and 11.), co-injection with n-butylamine (lines indicated as volatile amine "VA" in FIGS. 10 and 11) at 2,000 ppm resulted in accelerated oil production by 25% within the two year period during which the amine injection was forecast. It can be thus expected that injection of a suitable amine can shorten the time period to complete production, and may reduce the overall operation period by about 6 to 36 months depending on the particular reservoir and well condition and configuration. The results also suggest that overall oil recovery from the reservoir may not significantly increase in the VA case.
It can also be noted that the results show that the steam injection rate is higher during the two year period when amine is injected, due to increased fluid flow rate in the reservoir and thus increased production rate. However, iSOR is lower by 10%
during VA
operation, and overall steam usage and hence CSOR is reduced by about 1.0% in the VA
process as compared to the SAGD process. Due to a shorter project lifetime, there may be reduced heat losses to the overburden, making for a more efficient process and reduced overall CSOR.
In view of the test results, it may be reasonably expected that in an actual production operation, oil production rates in the initial period of co-injection with 0.1 wt% to 0.2 wt% of the selected volatile amine could be increased by about 10%
to 25%, as compared to continued pure steam injection.
Example 7 ¨ Geochemical Modelling Wellbore scaling induced by high pH water in the presence of amines could have an immediate impact on both well liners and facility treating units, for example, resulting in liner plugging or failure, pump failure, or accumulation of fines (scaling). To understand the geochemical effects of certain amines in the wellbore, geochemical modeling of a production well liner was based on average produced water chemistry from an Athabasca oil sands operation in Northern Alberta. Propylamine and butylamine were selected as test amines. The modeling was performed using the PHREEQC and MINTEQ4F program (see Parkhurst, D.L., and Appelo, C.A.J., 2013, Description of input and examples for PHREEQC version 3 ¨ A computer program for speciation, batch-reaction, one-dimensional transport, and inverse geochemical calculations: U.S.

Geological Survey Techniques and Methods, book 6, chap. A43, 497 p., available at http://pubs.uses.gov/tm/06/a43). The program includes various thermodynamic databases that provide the speciation reactions used by the program to prepare the model simulations. For these simulations the LLNL.dat database was the primary database.
Reactions for propylamine and butylamine were obtained from the MINTEQ.v4.dat database, and these additional reactions were included in the modeling input files.
TABLE VII lists produced water parameters included in the modeling.
TABLE VII. Produced Water Parameters Used in Geochemical Modeling Cations Anions Other Parameters Ion mg/L Ion mg/L pH= 7.5 Na 332 Cr 495 Total Dissolved Solids (TDS) = 946 K IS Br Total Organic Carbon (TOC)= 400 ppm Ca 8.1 r Si()) =6.5 ppm Mg 1. I HCO3- 77 Aluminum = 2.5 ppm Ba 0.07 S042- 17 H,S = N.D.
Sr 0.06 C032- 0.00 Fe 0.03 OH- 0.00 Mn 0.01 The following aspects of co-injection of a volatile amine with steam were assessed:
- impact of temperature on produced water pH
- impact of injected amine concentration on produced water pH
- saturation indices of selected minerals at different amine concentrations Because propylamine and butylamine are weak bases that can change the pH of water, this can increase saturation indices especially for carbonate minerals, leading to enhanced precipitation for these phases. However, it was observed during modeling of the potential for carbonate mineral formation on a production liner, that increasing 5 temperatures may reduce this influence.
Simple models were prepared to estimate the pH of propylamine and butylamine in pure water as a function of pH. The models assessed concentrations of 100 mg/L, 2,000 mg/L and 10,000 mg/L each of propylamine and butylamine. It was assumed for the model that 100% of the amine would be produced to surface with the produced 10 oil/water emulsion. The liner scale precipitation was determined to be mainly driven by changes in temperature impacting produced water pH rather than amine concentration within the range of concentrations tested. At higher temperatures and generally within a temperature range of about 210 C to 225 C, pH in the presence of amine remained relatively low, suggesting that carbonate scale may be limited.
15 Modelling showed that carbonates (for example, calcite/magnesite and dolomite) may be formed in the presence of 2,000 ppm amine at a saturation index (Si) of about 2, suggesting supersaturation of the water. The model also showed that sands/fines scaling was not an issue due to the process occurring at a relatively high pH (>8) compared to the produced water (having a pH of about 7.8-8). Without being limited to theory, the co-20 injection of amine with steam may actually keep silica in the water phase and prevent scaling at a relatively high pH. In the presence of 400 ppm SiO2, and a relatively high Fe level of 10 ppm, smectite (swelling clay) scale may form at lower temperatures, such as about 100 C to 150 C.
In the event that a well kill fluid is required (for example, in a scenario of an 25 operational shutdown), a high temperature low pH chelant (for example, glutamic acid diacetic acid classes) may be used to minimize scale formation (for example, carbonates and smectites) that may result in the presence of amine due to the temperature reduction expected in the near wellbore region during such a scenario.
If the wellbore productivity is affected due to scale deposition, chemical 30 stimulation (injection), for example an acid stimulation (for example, using a 1% aqueous solution of HO) may be performed as would be understood by a person of skill in the art to improve productivity and reduce near wellbore damage.
In high levels of fines (i.e. sands) are observed during analysis of produced water samples taken at surface, a high pH .fluid (e.g. NTA or DTPA) may be injected to reduce the silicates/silica scale that may be induced by co-injecting amine with steam.
OTHER POSSIBLE EMBODIMENTS AND VARIATIONS
It is contemplated that a factor that will influence the co-injection of a volatile JO amine and steam is the actual quantity of volatile agent injected. For example, under-dosage of the volatile agent injected into the reservoir may decrease the effectiveness of some methods described herein. An over-dosage of the volatile agent may potentially produce back free ammonia in the produced fluids. It is contemplated that the volatile agent co-injection may consist of the co-injection of saturated steam and between about 10 ¨ 10,000 ppm of volatile agent, or about 2,000 ppm of volatile agent. For example, steam may comprise about 99.8% of the injection fluid and volatile agent may comprise about 0.2% by weight. The concentration of volatile agent may be relatively low and may vary throughout the course of the well life and/or production processes.
Without limitation, it is contemplated that the volatile agent co-injected with steam may he selected to generate or provide a solvent-like effect (e.g., to provide dilution with the oil) or to react with a suitable acid present in the formation to generate a surfactant in situ, which can provide a surfactant-like effect (e.g., to reduce IF!).
Furthermore, it is contemplated that when co-injecting a volatile agent with steam, wherein the ratio of volatile agent to steam is between about 5:95 to 25:75 by weight (i.e., 5 wt% to 25 wt% of volatile agent based on total weight of volatile agent and steam), the solvent-like effect is dominant. Alternatively, it is contemplated that when injecting a volatile agent with steam, wherein the ratio of volatile agent to steam is between about.
0.02:99.98 to 2:98 by weight (i.e., 0.02 wt% to 2 wt% of volatile agent), the surfactant-like effect is dominant.

Traditionally, the final phase of SAGD is the blowdown phase that may consist of the co-injection of an Acme (for example, methane). Traditionally, during the blowdown phase, there is a transition where steam injection ceases and is replaced by, for example, methane injection. This reduces operating costs and maintains the reservoir pressure. In one embodiment, it is contemplated that the methane may be co-injected with both steam and a volatile agent prior to proceeding to full blowdown, where the injection of methane alone begins.
The injection well may be exclusively used for introducing the injection fluid, and the production welt may be exclusively used for the recovery of production fluids. It is further understood that a method disclosed herein does not necessitate the use of any external means within the well or reservoir to establish communication between well pairs or to increase hydrocarbon recovery (e.g., a heating device/pump, a vibration source, conduits, artificial barriers, electricity conducting devices, and the like).
A common consideration for selecting the suitable volatile agent is cost versus .. benefits.
Broadly speaking, an embodiment of the present disclosure may be directed to a method of producing hydrocarbons from a subterranean hydrocarbon reservoir, the method comprising injecting fluid into the reservoir, the fluid comprising at least steam and a volatile agent, the fluid being capable of synergistically improving mobility of .. viscous hydrocarbons in the formation, such as by reducing the interfacial tension between the hydrocarbons and water, and producing hydrocarbons from the hydrocarbon reservoir. In particular, "synergistically" may refer to the injected volatile agent providing a plurality of beneficial effects that together enhance oil production or economics of oil production more than any one of these effects would provide by itself.
In some embodiments, a method disclosed herein may be particularly useful when the formation bitumen is acidic and the viscous hydrocarbons in the formation are mixed with or contain organic acids such as carboxylic acids or naphthenic acids.
A method disclosed herein can improve oil production rates in some embodiments. Although the overall oil recovery factor may not be improved, acceleration of oil production is still beneficial as it provides higher production efficiency and can lower overall costs and time required for the hydrocarbon recovery process.
CONCLUDING REMARKS
Various changes and modifications not expressly discussed herein may be apparent and may be made by those skilled in the art based on the present disclosure. For example, while a specific example is discussed above with reference to a SAGD
process, some changes may be made when other recovery processes, such as CSS, are used.
It will be understood that any range of values herein is intended to specifically include any intermediate value or sub-range within the given range, and all such intermediate values and sub-ranges are individually and specifically disclosed.
It will also be understood that the word "a" or "an" is intended to mean "one or more" or "at least one", and any singular form is intended to include plurals herein.
It will be further understood that the term "comprise", including any variation thereof, is intended to be open-ended and means "include, but not limited to,"
unless otherwise specifically indicated to the contrary.
When a list of items is given herein with an "or" before the last item, any one of the listed items or any suitable combination of two or more of the listed items may be selected and used.
Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof.

Claims

WE CLAIM:

1. A method of producing hydrocarbons from a subterranean reservoir comprising viscous hydrocarbons and an organic acid in a recovery process wherein steam is injected into the reservoir to heat and mobilize the viscous hydrocarbons and mobilized hydrocarbons are produced from the reservoir, the method comprising:
injecting a vapor of n-butylamine or n-propylamine into the reservoir to react with the organic acid to form a surfactant, the surfactant capable of reducing an interfacial tension between a hydrocarbon and water.

2. The method of claim 1, comprising injecting into the reservoir a mixture comprising steam and about 0.1 wt% to about 0.2 wt% of n-butylamine or n-propylamine.

3. The method of claim 1 or claim 2, wherein the steam and the vapor of n-butylamine or n-propylamine are injected into the reservoir at a temperature of about 170 °C to about 240 °C.

4. The method of any one of claims 1 to 3, wherein the organic acid comprises a naphthenic acid.

5. The method of any one of claims 1 to 4, wherein n-butylamine or n-propylamine is injected into the reservoir at a concentration selected to reduce a total acid number in a fluid produced from the reservoir by at least 30%.

6. The method of claim 5, wherein the total acid number is reduced by at least 70%.

7. The method of any one of claims 1 to 6, wherein n-butylamine or n-propylamine is injected into the reservoir at a rate selected to accelerate hydrocarbon production from the reservoir by at least about 10% to about 25%.

8. The method of any one of claims 1 to 7, wherein n-butylamine is injected into the reservoir.

9. The method of any one of claims 1 to 8, wherein n-propylamine is injected into the reservoir.

10. A method of producing hydrocarbons from a subterranean reservoir comprising viscous hydrocarbons and an organic acid in a recovery process wherein steam is injected into the reservoir to heat and mobilize the viscous hydrocarbons and mobilized hydrocarbons are produced from the reservoir, the method comprising:
injecting a vapor of a volatile amine into the reservoir to react with the organic acid to form a surfactant, the surfactant capable of reducing an interfacial tension between a hydrocarbon and water, wherein the volatile amine is selected such that the selected volatile amine is more volatile than steam in the reservoir, and has a boiling point of about 45°C to about 80 °C.

11. The method of claim 10, comprising injecting into the reservoir a mixture comprising steam and about 0.1 wt% to about 0.2 wt% of the selected volatile amine.

12. The method of claim 10 or claim 11, wherein the steam and the selected volatile amine are injected into the reservoir at an injection temperature of about 170 °C to about 240 °C.

13. The method of any one of claims 10 to 12, wherein the organic acid comprises a naphthenic acid.

14. The method of any one of claims 10 to 13, wherein the selected volatile amine is injected into the reservoir at a concentration selected to reduce a total acid number in a fluid produced from the reservoir by at least 30%.

15. The method of claim 14, wherein the total acid number is reduced by at least 70%.

16. The method of any one of claims 10 to 15, wherein the selected volatile amine is injected into the reservoir at a rate selected to accelerate hydrocarbon production from the reservoir by at least 10% to 25%.

17. The method of any one of claims 10 to 16, wherein the selected volatile amine has a pKa of at least 10.

18. The method of any one of claims 10 to 17, wherein the selected volatile amine is more soluble in the hydrocarbons than in water at a steam chamber front in the reservoir.

19. The method of any one of claims 10 to 18, wherein the selected volatile amine has a linear hydrocarbon chain.

20. The method of any one of claims 10 to 19, wherein the volatile amine comprises a basic component and a hydrocarbon component.

21. The method of claim 20, wherein the basic component comprises at least one amino group.

22. The method of any one of claims 10 to 21, wherein the volatile amine is thermally stable.

23. The method of any one of claims 10 to 22, wherein the selected volatile amine is a primary amine.

24. The method of any one of claims 1 to 23, further comprising injecting a solvent into the reservoir to assist production of hydrocarbon from the reservoir.

25. The method of claim 24, wherein the solvent comprises propane.

26. The method of claim 24 or claim 25, wherein the solvent comprises butane.

27. The method of any one of claims 1 to 26, wherein the steam is injected at a pressure of about 2 MPa to about 4 MPa.

28. The method of any one of claims 1 to 9, wherein n-butylamine or n-propylamine is injected into the reservoir for a period of 9 to 24 months.

29. The method of any one of claims 1 to 9 and 28, comprising injecting n-butylamine or n-propylamine at different injection concentrations at different times.

30. The method of any one of claims 1 to 9 and 28 to 29, wherein when n-butylamine or n-propylamine is injected into the reservoir, a rate of steam injection is increased.

31. The method of any one of claims 10 to 23, wherein the volatile amine is injected into the reservoir for a period of 9 to 24 months.

32. The method of any one of claims 10 to 23 and 31, comprising injecting the volatile amine at different injection concentrations at different times.

33. The method of any one of claims 10 to 23 and 31-32, wherein when the volatile amine is injected into the reservoir, a rate of steam injection is increased.