Note: Descriptions are shown in the official language in which they were submitted.
1
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
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
3
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.
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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.
CA 02958449 2017-02-16
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.
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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.
CA 02958449 2017-02-16
7
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 ,
CA 02958449 2017-02-16
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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
CA 02958449 2017-02-16
9
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
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
11
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
CA 02958449 2017-02-16
12
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.
CA 02958449 2017-02-16
13
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
CA 02958449 2017-02-16
14
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.,
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
16
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.
CA 02958449 2017-02-16
17
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
CA 02958449 2017-02-16
18
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-
12
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
CA 02958449 2017-02-16
19
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).
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
21
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.
CA 02958449 2017-02-16
22
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
CA 02958449 2017-02-16
23
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
CA 02958449 2017-02-16
24
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.
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
26
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
CA 02958449 2017-02-16
27
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
CA 02958449 2017-02-16
28
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
CA 02958449 2017-02-16
29
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
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
31
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,
CA 02958449 2017-02-16
39
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
CA 02958449 2017-02-16
33
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.
CA 02958449 2017-02-16
34
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.
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
36
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.
CA 02958449 2017-02-16
37
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
131-1
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
-1
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
CA 02958449 2017-02-16
38
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
CA 02958449 2017-02-16
39
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.
CA 02958449 2017-02-16
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.
CA 02958449 2017-02-16
41
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
CA 02958449 2017-02-16
42
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
CA 02958449 2017-02-16
43
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.
CA 02958449 2017-02-16
44
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
CA 02958449 2017-02-16
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
CA 02958449 2017-02-16
46
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.
CA 02958449 2017-02-16
47
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
CA 02958449 2017-02-16
48
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.
