Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
FOAM DISPLACEMENT PROCESS FOR SOLVENT DRIVEN HYDROCARBON
RECOVERY PROCESS
TECHNICAL FIELD
[0001] The present disclosure generally relates to in situ methods
for
recovering hydrocarbons from subterranean reservoirs. In particular, the
present
disclosure relates to methods that utilize foam injection to facilitate
solvent driven
heavy hydrocarbon recovery.
BACKGROUND
In situ recovery of heavy hydrocarbons
[0002] Hydrocarbons, in some subterranean deposits of viscous
hydrocarbons, can be extracted in situ by lowering the viscosity of the
hydrocarbons
to mobilize them so that they can be moved to, and recovered from, a
production well.
Reservoirs of such deposits may be referred to as reservoirs of heavy
hydrocarbons,
heavy oil, bitumen, oil sands, or (previously) tar sands. In situ processes
for
recovering oil from oil sands typically involve the use of multiple wells
drilled into the
reservoir, and are assisted or aided by thermal recovery techniques, such as
injecting
a heated fluid, typically steam, into the reservoir from an injection well.
One process
of this kind is steam-assisted gravity drainage (SAGD) which involves a
horizontal
well pair (e.g. an injection well and a production well) configured to
facilitate steam
injection and oil production.
[0003]
Atypical SAGD process is disclosed in Canadian Patent No. 1,130,201
issued on 24 August 1982, in which the functional unit involves two wells that
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
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toward the production well with an aqueous condensate. In this way, the
injected
steam initially mobilizes the in-place hydrocarbons to create a "steam
chamber" in
the reservoir around and above the horizontal segment of the 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 typically 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 and maximize oil
production
at the production well.
[0004] The SAGD process has a number of shortcomings. For example, it is
an energy intensive process that may results in significant greenhouse gas
emissions. Also, SAGD processes may foul local water resources and may thus
require extensive water treatment. Accordingly, alternative processes for in
situ
hydrocarbon recovery that are aided by fluids other than steam have also been
proposed. Solvents are one such example. In the present disclosure, recovery
processes that are aided by one or more solvents are referred to as solvent-
aided
processes (SAP). In some SAP, the injection fluid may include less than about
20 %
solvent and greater than about 80 % steam on a mass basis. Such processes are
referred to herein as "steam-driven solvent-aided processes". In some SAP, the
injection fluid may include between about 20 % and about 80 % solvent on a
mass
basis. Such processes are referred to herein as "hybrid solvent-assisted
processes".
In some SAP, the injection fluid may include greater than about 80 % solvent
and less
than about 20 % steam on a mass basis. Such processes are referred to herein
as
"substantially solvent driven or in some cases solvent-only processes". In the
present
.. disclosure, the term "solvent driven recovery process (SDRP)" is used to
refer to both
hybrid solvent-assisted processes and substantially solvent-only processes.
Accordingly, the injection fluid used in a SDRP typically includes greater
than about
20 % solvent on a mass basis.
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[0005]
SDRP can be used in conjunction with other recovery processes such
as steam only processes. One such example is a process commonly referred to as
"combined steam and vapor extraction (SAVEX)" in which steam is injected until
an
upper surface of the steam chamber has progressed to 25 to 75 percent of the
distance from the bottom of the injection well to the top of the reservoir, or
until the
recovery rate of hydrocarbons is about 25 to 75 percent of the peak predicted
recovery rate using SAGD. When the condition is met, steam injection is
suspended
and replaced with a substantially solvent-only process.
[0006]
One of the goals in modifying existing SAGD (and other processes that
utilize steam) is to reduce the cumulative steam to oil ratio (CSOR). The CSOR
is an
important metric for assessing the performance and efficiency of a steam-
assisted
recovery process. Likewise the solvent-oil ratio (SvOR) is an important metric
for
assessing the performance and efficiency of a SDRP.
Foams and hydrocarbon recovery
[0007] A Foam is a type of emulsion. Emulsions consist of an internal phase
and an external phase (i.e. the continuous phase). In a foam, the internal
phase is a
gas phase and the external phase is a liquid. Foams are stabilized by surface-
active
agents commonly referred to as surfactants. In porous media, the liquid phase
of a
foam may be in contact with a matrix of pore walls such that the gas phase
consists
primarily of individual bubbles that are separated by liquid partitions. Such
partitions
are commonly referred to as "lamella". Foam is generally thought to propagate
within
porous media (e.g. a reservoir) as a "bubble train" in which a plurality of
gas bubbles
and liquid lamella films move in concert.
[0008]
Foams are generally metastable entities. Foam breakdown may result
from thinning of liquid films to the point of rupture. Foam breakdown results
in the gas
phase transitioning from a plurality of smaller bubbles into a plurality of
larger bubbles
or into a complete separation of the gas a liquid phase components. External
effects,
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such as contact with a foam breaker (e.g. a hydrocarbon) or localized heating
can
expedite foam breakdown.
[0009] Foams have been described for use in thermal recovery
processes for
blocking the breakthrough of an injection fluid into an undesirable location
within a
formation. Such locations are generally described as having relatively high
permeabilities, and the tendency of foams to preferentially flow to areas of
higher
permeability can allow them to act as a plug. For example, U.S. Patent No.
4,495,995
claims a process for temporarily plugging permeable portions of a subterranean
formation. Similarly, U.S. Patent No. 4,706,752 claims a method for reducing
the
permeability of higher permeability zones of an oil bearing subterranean
reservoir
having heterogeneous permeability. In a similar vein, Canadian Patent
Application
Number 2,830,741 discloses methods of recovering heavy oil from a reservoir in
which a foam is injected into a water and/or gas containing layer that
overlies a heavy
oil containing layer so as to act as a blocking agent. Likewise, Canadian
Patent
Application Number 2,729,430 discloses injecting a foam as an artificial top
seal or
barrier to mitigate injection fluid loss to a thief zone.
[0010] An alternative application of foams for thermal recovery
processes
involves using a foam as an agent to push oil to a receiving well in secondary
oil
recovery. For example, U.S. Patent No. 3,342,256 claims the recovery of oil
from
subterranean oil-bearing formations wherein a CO2 flood is introduced into the
formation and then driven through the formation from an injection well to a
recovery
well by means of an aqueous drive liquid.
SUMMARY
[0011] In one aspect, the present disclosure relates to a SDRP that
is aided by
foam injection. The process is generally referred to as a foam displacement
process
(FDP), as foam is used to displace solvent within the hydrocarbon depleted
interior
region of a chamber. As demonstrated herein, after a SDRP reaches a certain
phase,
foam injection can reduce the SvOR for the process by driving solvent at the
center
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of the chamber to the chamber edge where it can better mix with and mobilize
heavy
hydrocarbons. The effect of foam injection on the SvOR of a SDRP is influenced
by
numerous factors ¨ some relating to the physical characteristics of the foam
and
others relating to the specifics of the SDRP. The present disclosure sets out
select
foam characteristics (such as foam composition, foam quality, and foam
mobility
reduction factor) and SDRP characteristics (such as injection timing, and
injection-
fluid content) adapted to reduce the SvOR. For example, the characteristics of
the
foam and the SDRP may be selected such that foam preferentially occupies an
interior volume of the chamber and thereby displaces solvent towards the
chamber
edge where it can act as a diluent to mobilize heavy hydrocarbons.
[0012] Select embodiments of the present disclosure relate to a
method of
recovering heavy hydrocarbons from a subterranean reservoir within which an
injection well and a production well are in fluid communication, the
subterranean
reservoir comprising a chamber having a hydrocarbon-depleted interior, the
method
comprising: (i) injecting an injection fluid into the chamber via the
injection well in an
amount that is sufficient to mobilize heavy hydrocarbons within the
subterranean
reservoir, the injection fluid comprising at least 20 wt % of a solvent; (ii)
recovering a
production fluid from the subterranean reservoir via the production well, the
production fluid comprising mobilized heavy hydrocarbons; and (iii) injecting
a foam
into the hydrocarbon-depleted interior of the chamber, wherein the foam is
injected
in an amount sufficient to occupy at least about 15 % of the volume of the
hydrocarbon-depleted interior such that the amount of the injection fluid that
is
sufficient to mobilize heavy hydrocarbons is reduced to a degree where the
solvent-
oil ratio is reduced by at least about 5 % on a mass basis.
[0013] In select embodiments, the foam is injected in an amount sufficient
to
occupy at least about 20 % of the volume of the hydrocarbon-depleted interior.
[0014] Select embodiments of the present disclosure relate to a
method of
recovering heavy hydrocarbons from a subterranean reservoir within which an
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injection well and a production well are in fluid communication, the
subterranean
reservoir comprising a chamber having a hydrocarbon-depleted interior, the
method
comprising: (i) injecting an injection fluid into the chamber via the
injection well in an
amount that is sufficient to mobilize heavy hydrocarbons within the
subterranean
reservoir, the injection fluid comprising at least 20 wt. % of a solvent; (ii)
recovering
a production fluid from the subterranean reservoir via the production well,
the
production fluid comprising mobilized heavy hydrocarbons; and (iii) injecting
a foam
into the hydrocarbon-depleted interior of the chamber, wherein the foam has a
mobility reduction factor which is between about 1.6 and about 3 and occupies
a
portion of the hydrocarbon-depleted interior of the chamber so as to reduce
the
amount of the injection fluid that is sufficient to mobilize heavy
hydrocarbons to a
degree where the solvent-oil ratio is reduced by at least about 5 % on a mass
basis.
[0015] In select embodiments, the mobility reduction factor of the
foam is
between about 1.6 and about 3. In select embodiments, the mobility reduction
factor
of the foam is between about 1.6 and about 2.2. In select embodiments, the
mobility
reduction factor of the foam is about 1.8.
10016] Select embodiments of the present disclosure relate to a
method of
recovering heavy hydrocarbons from a subterranean reservoir within which an
injection well and a production well are in fluid communication, the
subterranean
reservoir comprising a chamber having a hydrocarbon-depleted interior, the
method
comprising: (i) injecting an injection fluid into the chamber via the
injection well in an
amount that is sufficient to mobilize heavy hydrocarbons within the
subterranean
reservoir, the injection fluid comprising at least 20 wt. % of a solvent; (ii)
recovering a
production fluid from the subterranean reservoir via the production well, the
production fluid comprising mobilized heavy hydrocarbons; (iii) determining an
estimated recoverable hydrocarbon reserve for (i) and (ii); and (iv) injecting
a foam
into the hydrocarbon-depleted interior of the chamber, wherein the injecting
of the
foam is initiated when at least about 15 % on a mass basis of the estimated
recoverable hydrocarbon reserve has been recovered such that the foam occupies
a
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portion of the hydrocarbon-depleted interior of the chamber and the amount of
the
injection fluid that is sufficient to mobilize heavy hydrocarbons is reduced
to a degree
where the solvent-oil ratio is reduced by at least about 5 % on a mass basis.
[0017]
In select embodiments, the injecting of the foam is initiated when at
least about 20 % on a mass basis of the estimated recoverable hydrocarbon
reserve
has been recovered. In select embodiments, the injecting of the foam is
initiated when
at least about 25 % on a mass basis of the estimated recoverable hydrocarbon
reserve has been recovered. In select embodiments, the foam is injected in an
amount sufficient to occupy at least about 15 % of the volume of the
hydrocarbon-
depleted interior of the chamber. In select embodiments, the foam is injected
in an
amount sufficient to occupy at least about 20 % of the volume of the
hydrocarbon-
depleted interior of the chamber. In select embodiments, the foam has a foam
quality
of between about 15 % and about 40 %. In select embodiments, the foam has a
foam
quality of between about 17 % and about 30 %. In select embodiments, the foam
has
a foam quality of about 20 %. In select embodiments, the foam has a mobility
reduction factor which is between about 1.6 and about 3. In select
embodiments, the
foam has a mobility reduction factor which is between about 1.6 and about 2.2.
In
select embodiments, the foam has a mobility reduction factor which is about
1.8.
100181
Select embodiments of the present disclosure relate to a method of
recovering heavy hydrocarbons from a subterranean reservoir within which an
injection well and a production well are in fluid communication, the
subterranean
reservoir comprising a chamber having a hydrocarbon-depleted interior, the
method
comprising: (i) injecting an injection fluid into the chamber via the
injection well in an
amount that is sufficient to mobilize heavy hydrocarbons within the
subterranean
reservoir, the injection fluid comprising at least 20 wt. % of a solvent such
that at least
a fraction of the chamber is solvent saturated; (ii) recovering a production
fluid from
the subterranean reservoir via the production well, the production fluid
comprising
mobilized heavy hydrocarbons; and (iii) injecting a foam into the hydrocarbon-
depleted interior of the chamber, wherein the production fluid comprises a gas-
phase
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production fluid which comprises at least a portion of the solvent, and
wherein the
injecting of the foam is initiated when the solvent accounts for at least 60 %
on a
molar basis of the gas-phase production fluid for at least two weeks on a
continuous
basis such that the foam occupies a portion of the hydrocarbon-depleted
interior of
the chamber and the amount of the injection fluid that is sufficient to
mobilize heavy
hydrocarbons is reduced to a degree where the solvent-oil ratio is reduced by
at least
about 5 % on a mass basis.
[0019] In select embodiments, the injecting of the foam is initiated
when the
solvent accounts for at least 70 % on a molar basis of the gas-phase
production fluid.
In select embodiments, the injecting of the foam is initiated when the solvent
accounts
for at least 75 % on a molar basis of the gas-phase production fluid. In
select
embodiments, the foam is injected in an amount sufficient to occupy at least
about
% of the volume of the hydrocarbon-depleted interior of the chamber. In select
embodiments, the foam is injected in an amount sufficient to occupy at least
about
15 20 % of the volume of the hydrocarbon-depleted interior of the chamber.
In select
embodiments, the foam has a foam quality of between about 15 % and about 40 %.
In select embodiments, the foam has a foam quality of between about 17 % and
about
30 %. In select embodiments, the foam has a foam quality of about 20 %. In
select
embodiments, the foam has a mobility reduction factor which is between about
1.6
and about 3. In select embodiments, the foam has a mobility reduction factor
which
is between about 1.6 and about 2.2. In select embodiments, the foam has a
mobility
reduction factor which is about 1.8.
[0020] In select embodiments, the present disclosure relates to a
method of
recovering heavy hydrocarbons from a subterranean reservoir within which an
injection well and a production well are in fluid communication, the
subterranean
reservoir comprising a chamber having a hydrocarbon-depleted interior, the
method
comprising: (i) injecting an injection fluid into the chamber via the
injection well in an
amount that is sufficient to mobilize heavy hydrocarbons within the
subterranean
reservoir, the injection fluid comprising at least 20 wt. % on a mass basis of
a solvent;
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(ii) recovering a production fluid from the subterranean reservoir via the
production
well, the production fluid comprising mobilized heavy hydrocarbons and at
least a
portion of the solvent; and (iii) injecting a foam into the hydrocarbon-
depleted interior
of the chamber, wherein the injecting of the foam is initiated when the amount
of the
solvent in the production fluid is greater than about 30 A) on a mass basis
of the
amount of the solvent in the injection fluid for at least about one month on a
substantially continuous basis such that the foam occupies a portion of the
hydrocarbon-depleted interior of the chamber and the amount of the injection
fluid
that is sufficient to mobilize heavy hydrocarbons is reduced to a degree where
the
solvent-oil ratio is reduced by at least about 5 % on a mass basis.
[0021] In select embodiments, the injecting of the foam is initiated
when the
amount of the solvent in the production fluid is greater than about 35 % on a
mass
basis. In select embodiments, the injecting of the foam is initiated when the
amount
of the solvent in the production fluid is greater than about 40 % on a mass
basis. In
select embodiments, the foam is injected in an amount sufficient to occupy at
least
about 15 % of the volume of the hydrocarbon-depleted interior of the chamber.
In
select embodiments, the foam is injected in an amount sufficient to occupy at
least
about 20 % of the volume of the hydrocarbon-depleted interior of the chamber.
In
select embodiments, the foam has a foam quality of between about 15 % and
about
40 %. In select embodiments, the foam has a foam quality of between about 17 %
and about 30 %. In select embodiments, the foam has a foam quality of about 20
%.
In select embodiments, the foam has a mobility reduction factor which is
between
about 1.6 and about 3. In select embodiments, the foam has a mobility
reduction
factor which is between about 1.6 and about 2.2. In select embodiments, the
foam
has a mobility reduction factor which is about 1.8.
[0022] Select embodiments of the present invention relate to a
method of
recovering heavy hydrocarbons from a subterranean reservoir within which an
injection well and a production well are in fluid communication, the
subterranean
reservoir comprising a chamber having a hydrocarbon-depleted interior, the
method
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comprising: (i) injecting an injection fluid into the chamber via the
injection well in an
amount that is sufficient to mobilize heavy hydrocarbons within the
subterranean
reservoir, the injection fluid comprising at least 20 wt. % of a solvent; and
(ii)
recovering a production fluid from the subterranean reservoir via the
production well,
the production fluid comprising mobilized heavy hydrocarbons; and (iii)
injecting a
foam into the hydrocarbon-depleted interior of the chamber, wherein the foam
has a
foam quality of between about 15 % and about 40 % and occupies a portion of
the
hydrocarbon-depleted interior of the chamber such that the amount of the
injection
fluid that is sufficient to mobilize heavy hydrocarbons to a degree where the
solvent-
.. oil ratio is reduced by at least about 5 % on a mass basis.
[0023] In select embodiments, the foam has a foam quality of between
about
17 AD and about 30 %. In select embodiments, the foam has a foam quality of
about
%. In select embodiments,
[0024] Select embodiments of the present disclosure relate to methods
in
15 which the foam comprises a gas-phase component, an aqueous-phase
component,
and a surfactant. In select embodiments, the foam comprises between about 0.1
A
and about 0.5 % of the surfactant on a mass basis. In select embodiments, the
gas-
phase component of the foam comprises a C2-C9 hydrocarbon. In select
embodiments, the gas-phase component of the foam comprises propane, butane, or
20 a combination thereof. In select embodiments, the aqueous-phase
component of the
foam comprises condensed steam, ground water, waste water, or brine. In select
embodiments, the surfactant is an alkyl benzene sulfonate, an alpha olefin
sulfonate,
an internal olefin sulfonate, an alkyl aryl sulfonate, an alkoxy sulfate, an
alcohol
ethoxylate, a primary alcohol, or a combination thereof. In select
embodiments, the
surfactant is an internal olefin sulfonate having between 20 and 24 carbon
atoms. In
select embodiments, the surfactant is EnordetTM 0242 as manufactured by Shell
Chemicals. In select embodiments, the foam is injected through the injection
well. In
select embodiments, the foam is injected through a tertiary well. In select
embodiments, the foam is injected at a pressure between about 3,250 kPa and
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CA 3030920 2019-01-18
3,750 kPa. In select embodiments, the hydrocarbon-depleted interior of the
chamber
has a permeability between about 2,000 mD and about 8,000 mD. In select
embodiments, the solvent of the injection fluid comprises a 02-C9 hydrocarbon.
In
select embodiments, the solvent of the injection fluid comprises, propane,
butane, or
a combination thereof. In select embodiments, the solvent and the gas-phase
component of the foam have the same composition. In select embodiments, the
injection fluid further comprises steam and the ratio of the solvent to the
steam in the
injection fluid is between about 1:4 and about 4:1. In select embodiments, the
injection fluid is injected at a pressure between about 3,250 kPa and about
3,750
kPa. In select embodiments, the injection well and the production well are
each
horizontal wells. In select embodiments, the solvent-oil ratio is reduced by
at least
about 10 % on a mass basis. In select embodiments, the solvent-oil ratio is
reduced
by at least about 15 A) on a mass basis. In select embodiments, the solvent-
oil ratio
is reduced by at least about 20 % on a mass basis.
BRIEF DESCRIPTION OF THE DRAWINGS
[0025] These and other features of the present disclosure will become
more
apparent in the following detailed description in which reference is made to
the
appended drawings. The appended drawings illustrate one or more embodiments of
the present disclosure by way of example only and are not to be construed as
limiting
the scope of the present disclosure.
[0026] FIG. 1 schematically illustrates a typical SAGD well pair in a
hydrocarbon reservoir, which can be operated to implement an embodiment of the
present disclosure.
[0027] FIG. 2 schematically illustrates the well pair of FIG.1
contacting a
hydrocarbon depleted chamber formed within the reservoir.
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[0028] FIG. 3 illustrates an example foam displacement process (FDP)
in the
context of a broader recovery process that includes a SAGD stage and an SDRP
stage.
[0029] FIG. 4 provides simulation data showing solvent and foam
accumulation within a chamber for an example FDP.
[0030] FIG. 5 provides simulation data showing foam mobility
reduction factor
as a function of foam quality.
[0031] FIG. 6 provides simulation data showing solvent and foam
accumulation within a chamber for an example FDP based on high quality foam
(left
panel) vs. SDRP only (no foam; right panel).
[0032] FIG. 7 provides simulation data showing solvent and foam
accumulation within a chamber for an example FDP based on low quality foam
(left
panel) vs. SDRP only (no foam; right panel).
[0033] FIG. 8 provides simulation data showing solvent and foam
.. accumulation within a chamber for an example FDP based on high quality foam
(left
panel) vs. low quality foam (right panel).
[0034] FIG. 9 provides simulation data showing solvent and foam
accumulation within a chamber for an example FDP based on how the foam is
injected into the chamber. In the example illustrated in the left panel, the
foam is
injected via a horizontal well. In the example illustrated in the right panel,
the foam is
injected via a vertical well.
[0035] FIG. 10 provides simulation data showing solvent and foam
accumulation within a chamber for an example FDP based on high quality foam
(left
panel) vs. low quality steam injection (right panel).
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[0036] FIG. 11 provides simulation data as a plot of cumulative oil
production
as a function of time after operation for an example low quality steam
injection case,
an example foam injection from a vertical well case, and an SDRP only case.
[0037] FIG. 12 provides simulation data as a plot of cumulative oil
production
as a function of time after operation for an example high quality foam
injection case
and an example low quality foam injection case as compared to an SDRP only
case.
[0038] FIG. 13 provides simulation data as a plot of cumulative
solvent
injection on a gas phase basis as a function of time after operation for an
example
high quality foam injection case and an example low quality foam injection
case as
compared to an SDRP only case.
[0039] FIG. 14 provides simulation data as a plot of solvent-oil-
ratio (SvOR) as
a function of time after operation for an SDRP case, an example high quality
foam
injection case, and an example low quality foam injection case.
[0040] FIG. 15 provides simulation data as a plot of foam quality as
a function
of injection pressure.
DETAILED DESCRIPTION
Definitions
[0041] In the context of the present application, various terms are
used in
accordance with what is understood to be the ordinary meaning of those terms.
For
example, "petroleum" is a naturally occurring mixture consisting predominantly
of
hydrocarbons in the gaseous, liquid or solid phase. In the context of the
present
application, the words "petroleum" and "hydrocarbon" are used to refer to
mixtures of
widely varying composition. The production of petroleum from a reservoir
necessarily
involves the production of hydrocarbons, but is not limited to hydrocarbon
production
and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V).
Similarly,
processes that produce hydrocarbons from a well will generally also produce
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petroleum fluids that are not hydrocarbons. In accordance with this usage, a
process
for producing petroleum or hydrocarbons is not necessarily a process that
produces
exclusively petroleum or hydrocarbons, respectively. "Fluids", such as
petroleum
fluids, include both liquids and gases. Natural gas is the portion of
petroleum that
exists either in the gaseous phase or in solution in crude oil in natural
underground
reservoirs, and which is gaseous at atmospheric conditions of pressure and
temperature. Natural gas may include amounts of non-hydrocarbons. The
abbreviation POIP stands for "producible oil in place" and in the context of
the
methods disclosed herein is generally defined as the exploitable or producible
oil
located above the production well elevation.
[0042]
It is common practice to segregate petroleum substances of high
viscosity and density into two categories, "heavy oil" and "bitumen". For
example,
some sources define "heavy oil" as a petroleum that has a mass density of
greater
than about 900 kg/m3. Bitumen is sometimes described as that portion of
petroleum
that exists in the semi-solid or solid phase in natural deposits, with a mass
density
greater than about 1,000 kg/m3 and a viscosity greater than 10,000 centipoise
(cP;
or 10 Pas) measured at original temperature in the deposit and atmospheric
pressure, on a gas-free basis. Although these terms are in common use,
references
to heavy oil and bitumen represent categories of convenience and there is a
continuum of properties between heavy oil and bitumen. Accordingly, references
to
heavy oil and/or bitumen herein include the continuum of such substances, and
do
not imply the existence of some fixed and universally recognized boundary
between
the two substances. In particular, the term "heavy oil" includes within its
scope all
"bitumen" including hydrocarbons that are present in semi-solid or solid form.
[0043] A "reservoir" is a subsurface formation containing one or more
natural
accumulations of moveable petroleum, which are generally confined by
relatively
impermeable rock. An "oil sand" or "oil sands" reservoir is generally
comprised of
strata of sand or sandstone containing petroleum. A "zone" in a reservoir is
an
arbitrarily defined volume of the reservoir, typically characterised by some
distinctive
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property. Zones may exist in a reservoir within or across strata or facies,
and may
extend into adjoining strata or facies. In some cases, reservoirs containing
zones
having a preponderance of heavy oil are associated with zones containing a
preponderance of natural gas. This "associated gas" is gas that is in pressure
communication with the heavy oil within the reservoir, either directly or
indirectly, for
example through a connecting water zone. A pay zone is a reservoir volume
having
hydrocarbons that can be recovered economically.
[0044] "Thermal recovery" or "thermal stimulation" refers to
enhanced oil
recovery techniques that involve delivering thermal energy to a petroleum
resource,
for example to a heavy oil reservoir. There are a significant number of
thermal
recovery techniques other than SAGD, such as cyclic steam stimulation (CSS),
in-
situ combustion, hot water flooding, steam flooding, and electrical heating.
In general,
thermal energy is provided to reduce the viscosity of the petroleum to
facilitate
production.
[0045] A "chamber" within a reservoir or formation is a region that is in
fluid/pressure communication with a particular well or wells, such as an
injection or
production well. For example, in a SAGD process, a steam chamber is the region
of
the reservoir in fluid communication with a steam injection well, which is
also the
region that is subject to depletion of hydrocarbons, often by gravity
drainage, into a
production well.
[0046] As used herein, the term "about" refers to an approximately
+/-10%
variation from a given value. It is to be understood that such a variation is
always
included in any given value provided herein, whether or not it is specifically
referred
to.
Description
[0047] Without being bound by any particular theory, it is postulated
that, after
a solvent driven recovery process (SDRP) reaches a certain phase where chamber
CA 3030920 2019-01-18
growth is generally steady at near equilibrium solvent variation within
chamber, the
solvent at the center of the chamber can be displaced with foam. In this
disclosure,
the foam (preferably at low foam quality), is injected to displace the solvent
in a SDRP
chamber. The propagation of the foam front in the interior of the chamber
helps push
the majority of the solvent to the chamber edge where it continues to mix and
mobilize
heavy hydrocarbons. This decreases the amount of solvent that would otherwise
be
required to operate the SDRP. The center of the chamber becomes a foam rich
area,
and the outer chamber becomes a solvent rich area.
100481 In select aspects, four parameters in the foam displacement
process
(FOP) may be taken into consideration in order to adapt the efficiency of the
process.
Firstly, capillary pressure destabilizes the foam at the foam/water/bitumen
interface,
which forces collapse of foam lamella resulting in immediate coalescence. This
destabilization phenomenon at the chamber edge may lead to a relatively low
foam
content near the edge of the chamber and a relatively high foam content near
the
chamber core. Having the foam stay more towards the center of the chamber may
promote solvent diffusion to the edge of the chamber where mixing and
mobilization
of cool bitumen occurs. Secondly, injecting low quality foam, which contains a
considerable amount of a liquid phase component (e.g. hot water), may
facilitate
mobilization of heavy hydrocarbons by providing latent heat. Thirdly, in
embodiments
where the gas-phase component of the foam is a diluent for heavy hydrocarbons,
the
gas which "leaks" away from the foam front due to foam collapse may move to
the
edges of the chamber where it may help with the viscosity reduction of the
bitumen
in the solvent/bitumen mixing zone. This may be particularly advantageous when
the
gas-phase component of the foam has the same composition as the solvent used
in
the SDRP phase. Fourthly, the adverse effect of oil on foam stability can
strongly
reduce the stability of foam and cause destabilisation and collapse. As a
result,
injected solvent may preferentially occupy the chamber edge as the injected
foam
may not be stable in this area.
16
CA 3030920 2019-01-18
[0049] For the purpose of promoting an understanding of the
principles of the
disclosure, reference will now be made to the features illustrated in the
drawings and
specific language will be used to describe the same. It will nevertheless be
understood that no limitation of the scope of the disclosure is thereby
intended.
[0050] FIG. 1 schematically illustrates a typical SAGD well pair in a
hydrocarbon reservoir, which can be operated to implement an embodiment of the
present disclosure.
[0051] As illustrated, a reservoir 100 containing heavy hydrocarbons
is below
an overburden 110. Under natural conditions (e.g. prior to the application of
a
recovery process), the reservoir 100 is at a relatively low temperature, such
as about
12 C, and the formation pressure may be from about 0.1 to about 4 MPa (1 MPa
=
1,000 Pa), depending on the location and other characteristics of the
reservoir. A pair
of SAGD wells, including an injection well 120 and a production well 130, is
drilled
into and extends substantially horizontally in the reservoir 100 for producing
hydrocarbons from the reservoir 100. The well pair is typically positioned
away from
the top of the reservoir 100 which, as depicted in FIG. 1, is defined by the
lower edge
of the overburden 110, and positioned near the bottom of a pay zone or
geological
stratum in the reservoir 100 as will be appreciated by those skilled in the
art.
[0052] As is typical of such SAGD configurations, the injection well
120 may
be vertically spaced from the production well 130, such as at a distance of
about 5
m. The distance between the injection well 120 and the production well 130 in
a
SAGD well pair may vary and may be selected to optimize the SAGD operation
performance, as can be understood by those skilled in the art. In select
embodiments,
the horizontal sections of the injection well 120 and the production well 130
may have
be about 800 m in length. In other embodiments, these lengths may be varied as
will
be understood and selected by those skilled in the art. The injection well 120
and the
production well 130 may each be configured and completed according to any
suitable
techniques for configuring and completing horizontal in situ wells known to
those
17
CA 3030920 2019-01-18
skilled in the art. The injection well 120 and the production well 130 may
also be
referred to as the "injector" and "producer", respectively.
[0053]
As depicted, the reservoir 100 underlies the overburden 110, which may
also be referred to as a cap layer or cap rock. The overburden 110 may be
formed of
a layer of impermeable material such as clay or shale. A region in the
reservoir 100
just below and near the overburden 110 may be considered as an interface
region
115.
[0054]
As illustrated, the injection well 120 and the production well 130 are
connected to respective corresponding surface facilities, which typically
include an
injection surface facility 140 and a production surface facility 150. The
injection
surface facility 140 is configured and operated to supply injection fluids,
such as
steam, solvent, foam, or combinations thereof into the injection well 120. The
production surface facility 150 is configured and operated to produce fluids
collected
in the production well 130 to the surface. Each of the injection surface
facility140 and
the production surface facility150 includes one or more fluid pipes or tubing
for fluid
communication with their respective wells. As depicted for illustration,
surface facility
140 may have a supply line connected to a steam generation plant for supplying
steam for injection, a supply connected to a solvent source for supplying the
solvent
for injection, and a supply connected to a foam source for supplying the foam
for
injection. Optionally, one or more additional supply lines may be provided for
supplying other fluids, additives or the like for co-injection with the steam,
the solvent,
the foam, or combinations thereof. Each supply line may be connected to an
appropriate source of supply, which may include, for example, a steam
generation
plant, a boiler, a fluid mixing plant, a fluid treatment plant, a truck, a
fluid tank, or the
like. In select embodiments, co-injected fluids or materials may be pre-mixed
before
injection. In other embodiments, co-injected fluids may be separately supplied
into
the injection well 120. In particular, the injection surface facility 140 may
be used to
supply steam into the injection well 120 in a first phase, a mixture of steam
and solvent
into the injection well 120 in a second phase, and foam into the injection
well 120 in
18
CA 3030920 2019-01-18
a third phase. In the second phase, the solvent may be pre-mixed with steam at
surface before co-injection. Alternatively, the solvent and steam may be
separately
fed into the injection well 120 for injection into the reservoir 100.
Optionally, the
injection surface facility 140 may include a heating facility (not separately
shown) for
pre-heating the solvent, the foam, or combinations thereof, before injection.
Optionally, a third well may be provided for injecting additives during the
first phase,
the second phase, or the third phase.
[0055] As illustrated, the production surface facility 150 includes a
fluid
transport pipeline for conveying produced fluids to a downstream facility (not
shown)
for processing or treatment. The production surface facility 150 includes
necessary
and optional equipment for producing fluids from the production well 130, as
can be
understood by those skilled in the art.
[0056] Other necessary or optional surface facilities 160 may also be
provided
as can be understood by those skilled in the art. For example, the surface
facilities
160 may include one or more of a pre-injection treatment facility for treating
a material
to be injected into the formation, a post-production treatment facility for
treating a
produced material, a control or data processing system for controlling the
production
operation or for processing collected operational data.
[0057] The injection well 120 and the production well 130 may be
configured
and completed in any suitable manner as can be understood or is known to those
skilled in the art, so long as they are compatible with injection and recovery
of steam,
solvent, foam, or combinations thereof as set out below.
[0058] FIG. 2 is a schematic perspective view of the injection well
120 and the
production well 130 in the reservoir 100 during a recovery process where a
vapor
chamber has formed. As illustrated, the injection well 120 has an injector
casing 220
and the production well 130 has a production casing 230. An injector tubing
225 is
positioned in the injector casing 220, the use of which can be understood by
those
skilled in the art. For simplicity, other necessary or optional components,
tools or
19
CA 3030920 2019-01-18
equipment that are installed in the injection well 120 and the production well
130 are
not shown in the drawings as they are not particularly relevant to the present
disclosure.
[0059] As depicted in FIG. 2, the injector casing 220 includes a
slotted liner
along the horizontal section of well 120 for injecting fluids into the
reservoir 100.
[0060] Production casing 230 is also completed with a slotted liner
along the
horizontal section of well 130 for collecting fluids drained from the
reservoir 100 by
gravity. In select embodiments, the production well 130 may be configured and
completed similarly to the injection well 120.
[0061] In select embodiments, each of the injection well 120 and the
production well 130 may be configured and completed for both injection and
production, which can be useful in some applications as can be understood by
those
skilled in the art.
[0062] FIG. 3 illustrates an example FDP in the context of a broader
recovery
process.
[0063] At S300, the reservoir 100 is subjected to an initial phase of
the SAGD
process, referred to as the "start-up" phase or stage, in which fluid
communication
between the injection well 120 and the production well 130 is established. To
permit
drainage of mobilized hydrocarbons and condensate to the production well 130,
fluid
communication between the injection well 120 and the production well 130 must
be
established. Fluid communication refers to fluid flow between the injection
and
production wells. Establishment of such fluid communication typically involves
mobilizing viscous hydrocarbons in the reservoir to form a reservoir fluid and
removing the reservoir fluid to create a porous pathway between the wells.
Viscous
.. hydrocarbons may be mobilized by heating such as by injecting or
circulating
pressurized steam or hot water through the injection well 120 or the
production well
130. In some cases, steam may be injected into, or circulated in, both the
injection
CA 3030920 2019-01-18
well 120 and the production well 130 for faster start-up. A pressure
differential may
be applied between the injection well 120 and the production well 130 to
promote
steam/hot water penetration into the porous geological formation that lies
between
the wells of the well pair. The pressure differential promotes fluid flow and
convective
heat transfer to facilitate communication between the wells.
[0064] Additionally or alternatively, other techniques may be
employed during
the start-up stage S300. For example, to facilitate fluid communication, a
solvent may
be injected into the reservoir region around and between the injection well
120 and
the production well 130. The region may be soaked with a solvent before or
after
steam injection. An example of start-up using solvent injection is disclosed
in CA
2,698,898. In further examples, the start-up phase S300 may include one or
more
start-up processes or techniques disclosed in CA 2,886,934, CA 2,757,125, or
CA
2,831,928.
[0065] Once fluid communication between the injection well 120 and
the
production well 130 has been achieved, oil production or recovery may commence
during stage S305. As the oil production rate is typically low initially and
will increase
as the vapor chamber develops, this early production phase is known as the
"ramp-
up" phase or stage. During the ramp-up stage S305, steam is typically injected
continuously into injection well 120, at constant or varying injection
pressure and
temperature. At the same time, mobilized heavy hydrocarbons and aqueous
condensate are continuously removed from the production well 130. During the
ramp-
up stage S305, the zone of communication between the injection well 120 and
the
production well 130 may continue to expand axially along the full length of
the
horizontal portions thereof.
[0066] As injected steam heats up the reservoir 100, heavy hydrocarbons in
the heated region are softened, resulting in reduced viscosity. Further, as
heat is
transferred from steam to the reservoir 100, steam condenses. The aqueous
condensate and mobilized hydrocarbons will drain downward due to gravity. As a
21
CA 3030920 2019-01-18
result of depletion of the heavy hydrocarbons, a porous region 260 is formed
in the
reservoir 100, which is referred to as a "vapor chamber." When a vapor chamber
is
filled with mainly steam, it is commonly referred to as a "steam chamber." The
aqueous condensate and hydrocarbons drained towards the production well 130
and
collected in the production well 130 are then produced (transferred to the
surface),
such as by gas lifting or through pumping as is known to those skilled in the
art.
[0067] As alluded to above, the vapor chamber 260 is formed and
expands
due to depletion of hydrocarbons and other in situ materials from regions of
the
reservoir 100 above the injection well 120. Injected steam tends to rise up to
reach
the top of the vapor chamber 260 before it condenses, and steam can also
spread
laterally as it travels upward. Therefore, during early stages of chamber
development,
the vapor chamber 260 expands upwardly and laterally from the injection well
120.
During the ramp-up stage S305, vapor chamber 260 can grow vertically towards
the
overburden 110.
[0068] Depending on the size of the reservoir 100 (and the pay therein) and
the distance between the injection well 120 and the overburden 110, it can
take a
long time, such as many months and up to two years, for the vapor chamber 260
to
reach the overburden 110 especially when the pay zone is relative thick as is
typically
found in some operating oil sands reservoirs. However, it will be appreciated
by those
.. skilled in the art that in a thinner pay zone, the vapor chamber 260 can
reach the
overburden 110 sooner. The time to reach the vertical expansion limit can also
be
longer in cases where the pay zone is higher or highly heterogeneous, or the
reservoir
100 has complex overburden geologies such as with inclined heterolithic
stratification
(HIS), top water, top gas, or the like.
[0069] In the next stage, the reservoir 100 is subject to a conventional
SAGD
production process S310, where the oil production rate is sufficiently high
for
economic recovery of hydrocarbons and the CSOR continues to decrease or remain
relatively stable.
22
CA 3030920 2019-01-18
[0070] During the conventional SAGD production process S310 (or a
similar
but modified steam-driven recovery process), one or more chemical additives
may be
added to steam or co-injected with steam to enhance hydrocarbon recovery. For
example, a surfactant, which lowers the surface tension of a liquid, the
interfacial
tension (IFT) between two liquids, or the (FT between a liquid and a solid,
may be
added. The surfactant may act, for example, as a detergent, a wetting agent,
an
emulsifier, a foaming agent, or a dispersant to facilitate the drainage of the
softened
hydrocarbons to the production well 130. An organic solvent, such as an alkane
or
alkene, may also be added to dilute the mobilized hydrocarbons so as to
increase the
mobility and flow of the diluted hydrocarbon fluid to the production well 130
for
improved recovery. Other materials in liquid or gas form may also be added to
enhance recovery performance. However, steam still plays the dominant role in
chamber development during such modified SAGD processes and the weight ratio
of
such other agents or additives in the injection stream is relatively low.
[0071] The start-up stage S300, the ramp-up stage S305, and the SAGD
production process stage S310 described above are non-limiting examples, and
there
are numerous conventional techniques known to those skilled in the art that
result in
the formation of a vapor chamber. In alternative embodiments, rather than
using a
well pair, one or more single horizontal or vertical wells may be used for
providing a
vapor chamber. For example, CA 2,844,345 to Gittins, discloses a process that
provides a vapor chamber using a single vertical or inclined well. The process
may
be preceded by start-up acceleration techniques to establish communication in
the
formation between an injection means and a production means within the single
well.
100721 In the case of single well embodiment, fluid communication
refers to
fluid flow in the formation between the injection means (or an injection
component)
and the production means (or a production component) in the single well. For
example, the injection and production components may be conduits, optionally
tubing, and may be isolated from one another by way of a packer, by
positioning the
injection and production means a suitable distance apart, by positioning the
injection
23
CA 3030920 2019-01-18
means in the wellbore closer to the surface than the production means in the
case of
a vertical well, or by way of openings or perforations in the tubing or well
casing over
selected wellbore interval(s) to permit both outlet of injected fluids and
inlet of
production fluids. The positioning of the injection and production means may
be
adapted depending on the particular well and formation. For example, processes
may
make use of an injection tubing string which has openings only at or towards
one end
of the horizontal well, for example at the toe end, to permit egress of
injected fluids,
and openings or perforations along the liner or outer casing of the wellbore
to permit
injection into the reservoir of mobilizing fluids over a selected interval of
the wellbore.
Positioned downstream therefrom along the casing or liner of that same
wellbore,
openings may be provided to permit production from the reservoir of mobile and
mobilized fluids. In addition, one or more surfactants can be used to
facilitate or
accelerate a single well start-up process, or to improve fluid communication.
[0073] When the vapor chamber 260 grows vertically, oil production
rate
normally continue to increase, and the CSOR normally continue to decrease.
Steam
utilization during such chamber growth is efficient. However, when the top
front of the
vapor chamber 260 approaches or reaches the overburden 110 or the transition
region 115, vertical growth of the vapor chamber 260 will slow down and
eventually
stop. While the vapor chamber 260 may continue to grow or expand laterally,
which
may be at a slower pace, steam utilization during slow lateral growth is less
efficient.
As a result, oil production rate may reach a peak value or plateau, and then
start to
decline. The CSOR may bottom out and start to increase. Thus, such changes in
chamber growth, oil production rate and CSOR may be used as a production
threshold for transitioning from the steam-driven process to the solvent-
driven
process.
[0074] To this end, at S315 a suitable solvent and transition
condition are
selected (according to the various factors and considerations as set out in CA
2,956,771) at S320 and S325 respectively. As can be appreciated by those
skilled in
the art, the selection at S320 and S325 may be performed at any time prior to
solvent
24
CA 3030920 2019-01-18
injection, and may be performed in any order depending on the particular
situation
and application.
[0075] At S320, the solvent for use in the solvent-driven process is
selected or
determined. A suitable solvent may be selected based on a number of
considerations
and factors as set out in CA 2,956,771. The solvent should be injectable as a
vapor,
and should be suitable for dissolving at least one of the heavy hydrocarbons
to be
recovered from the reservoir 100. The solvent may be a viscosity-reducing
solvent,
which reduces the viscosity of the heavy hydrocarbons in the reservoir 100.
Suitable
solvents may include C2 to C9 hydrocarbons such as, propane, butane, or
pentane.
For selecting a suitable solvent, the properties and characteristics of
various
candidate solvents may be considered and compared. For a given selected
solvent,
the corresponding operating parameters during co-injection of the solvent with
steam
should also be selected or determined in view the properties and
characteristics of
the selected solvent. The mass fraction of the solvent should be greater than
20 %
and enough steam must be added to make sure that the injected solvent is
substantially in the vapor phase. In a given application, the solvent may be
selected
based on its volatility and solubility in the reservoir fluid.
[0076] At S325, a transition condition for transitioning to the
solvent-driven
process is selected or determined. Transition conditions may be selected based
on a
number of considerations and factors as set out in CA 2,956,771. Transitioning
to the
solvent-driven process at an early stage in the SAGD process may be possible
in
some cases, but such early transition before the vapor chamber has fully
developed
vertically may limit the overall chamber growth or slow down the initial
chamber
growth. Further, when the transition occurs too early, the reservoir formation
contains
less heat transferred from steam and the heated region in the formation is
relatively
small. Without being limited to any specific theory, when the vapor chamber is
fully
developed vertically, the amount of heat transferred to the reservoir
formation and
the large region of heated area can be quite beneficial to the subsequent
solvent-
driven process. The heat, or higher formation temperature in a large region in
the
CA 3030920 2019-01-18
formation, can help to maintain the solvent in the vapor phase and assist
dispersion
of the solvent to the chamber front or edges. The heat from steam can also by
itself
assist reduction of viscosity of the hydrocarbons.
[0077] At S330, it is determined whether the transition condition
selected at
S325 has been met. This determination may be made based on a pre-set timing or
based on measured and predicted operational parameters and current reservoir
conditions. The determination may involve monitoring certain selected
parameters,
for example, monitoring of injection, production, downhole parameters, or
parameters
of the geological formation. For example, parameters such as CSOR,
temperatures,
pressures, or the like may be monitored. Such parameters may be measured at,
for
example, the injection well 120 and/or the production well 130. Additionally
or
alternatively, determining when a transition condition has been met may
involve
prediction based on indirect indicators that the condition has been met, such
as based
on assumptions derived from a model and informed by the aforementioned
monitoring.
[0078] When the transition condition has been met, the steam-driven
SAGD
process S310 is terminated and a solvent-driven process is started at S335.
The
solvent-driven process S335 involves injection of the selected solvent in
vapor form
into the reservoir 100 through the injection well 120. The solvent is injected
into the
reservoir 100 in a vapor phase. Injection of the solvent in the vapor phase
allows
solvent vapor to rise in the vapor chamber 260 and condense at a region away
from
the injection well 120. Allowing solvent to rise in the vapor chamber 260
before
condensing may achieve beneficial effects. For example, when solvent vapor is
delivered to the vapor chamber 260 and then allowed to condense and disperse
near
the edges of the vapor chamber 260, oil production performance, such as
indicated
by one or more of oil production rate, cumulative steam to oil ratio (CSOR),
and
overall efficiency, may be improved. Injection of solvent in the gaseous
phase, rather
than a liquid phase, may allow vapor to rise in the vapor chamber 260 before
condensing so that condensation occurs away from the injection well 120. It is
noted
26
CA 3030920 2019-01-18
that injecting solvent vapor into the vapor chamber does not necessarily
require
solvent be fed into the injection well 120 in vapor form. For example, the
solvent may
be heated downhole and vaporized in the injection well 120.
[0079]
The total injection pressure for solvent and steam co-injection during
stage S335 may be the same or different than the injection pressure during the
SAGD
production stage S310. For example, the injection pressure may be maintained
at
between 2 MPa and 3.5 MPa, or up to 4 MPa. Alternatively, steam may be
injected
at a pressure of about 3 MPa in the SAGD process S310, while steam and solvent
are co-injected at a pressure of about 2 MPa to about 3.5 MPa in the solvent-
driven
process S335.
[0080]
In S335, the solvent may be heated to vaporize the solvent. For
example, when the solvent is propane, it may be heated with hot water at a
selected
temperature such as, for example, about 100 C. Additionally or alternatively,
solvent
may be mixed or co-injected with steam to heat the solvent to vaporize it and
to
maintain the solvent in vapor phase. Depending on whether the solvent is pre-
heated
at surface, the weight ratio of steam in the injection stream should be high
enough to
provide sufficient heat to the co-injected solvent to maintain the injected
solvent in
the vapor phase. If the feed solvent from surface is in the liquid phase, more
steam
may be required to both vaporize the solvent and maintain the solvent in the
vapor
phase as the solvent travels through the vapor chamber 260. For example, where
the
selected solvent is propane, a solvent-steam mixture containing about 90 %
propane
and about 10 % steam on a mass basis may be injected at a suitable
temperature,
such as about 75 C to about 100 C. Such a suitable steam temperature may be
determined, for example, through techniques as known to persons of skill in
the art
based on parameters of the mixture components. For example, the enthalpy per
unit
mass of the aforementioned steam-propane mixture may be about 557 kJ/kg.
[0081]
The total volume of the solvent injected during the solvent-driven
process S335 may be lower than the total volume of steam injected during SAGD.
27
CA 3030920 2019-01-18
[0082] In S335, co-injection of steam and the solvent may be carried
out in a
number of different ways or manners as can be understood by those skilled in
the art.
For example, co-injection of the solvent and steam into the vapor chamber may
include gradually increasing the weight ratio of the solvent in the co-
injected solvent
and steam, and gradually decreasing the weight ratio of steam in the co-
injected
solvent and steam. At a later time within S335, the solvent content in the co-
injected
solvent and steam may be gradually decreased, and the steam content in the co-
injected solvent and steam may be gradually increased. For example, depending
on
market factors, the cost of solvent may change over the life of such a
process. During
.. or after the solvent-driven process S335, it may be of economic benefit to
gradually
decrease the solvent content and gradually increase the steam content.
[0083] In alternate embodiments, S315, S320, S325, S330, and S335
are
applied to single well configurations. The application of S315, S320, S325,
S330, and
S335 to a single well configuration is within the purview of those skilled in
the art
having regard to the present disclosure and will not be set out in detail.
[0084] In the next stage (S340) a suitable foam and a suitable
transition
condition are selected as described herein (S345 and S350, respectively). The
selections at S345 and S350 may be performed at any time prior to foam
injection,
and may be performed in any order depending on the particular situation and
.. application.
[0085] In S345, selecting the foam requires selecting a gas-phase
component,
a liquid-phase component, and a surfactant.
[0086] In a preferred embodiments, the gas-phase component, will
generally
have the same composition as the solvent in S335. Of course, the gas-phase
component of S345 is not required to be the same as the solvent of S335, but
because it is already on site and configured for injection, it provides a
convenient
option. In the FDP, the gas-phase component of the foam should be
substantially in
the gas phase as it is injected into the reservoir. Thus, in select
embodiments, the
28
CA 3030920 2019-01-18
gas phase component will be in liquid form at the surface and will typically
have a
temperature similar to the ambient air temperature on that day. In select
embodiments, the only heat that is used to fully vaporize the gas-phase
component
before it hits the reservoir comes from the injected steam, and to a much
lesser
degree any heated water which may be added.
[0087]
The liquid phase component may be heated water (having a
temperature of, for example, 90 C). The heated water can be reservoir brine
or any
other water that when added with steam does not form a substantial amount of
precipitates or unwanted gasses. The role of the liquid phase component is the
"make-up liquid" for lamella generation. In select embodiments, the liquid
phase
component may be condensed steam. In particular, in select embodiments, a
quantity
of steam will be added to the foam mixture in order to condense after
transferring its
latent heat to the gas-phase component to heat it up and/or vaporize it. This
condensed steam, along with the surfactant will form the bulk of the lamella
of the
foam.
[0088]
The foam may also include steam. Injecting steam during the FDP
process may serve two functions. Firstly, the steam may act as a heat source
for
vaporizing the gas-phase component prior to injection. The second function is
that
the condensed water from the steam may form the lamella, along with any heated
water that is added to the process and the surfactant that is used to create
the lamella.
[0089]
Selecting the foam in S345 also involves selecting a surfactant. The
role of the surfactant is to create an interface between the gas-phase
component of
the foam and the liquid-phase component of the foam. This interface creates
the
lamella which constitute the continuous phase of the foam used during FDP. The
surfactant can be one of many functional surfactant groups including an alkyl
benzene
(aromatic) sulfonate, an alpha olefin sulfonates, an internal olefin
sulfonate, an alkyl
aryl sulfonate, an alkoxy sulfate, an alcohol ethoxylate, a primary alcohol,
or a straight
chain alcohol like methanol and ethanol. A preferred embodiment for the
surfactant
29
CA 3030920 2019-01-18
is an internal olefin sulfonate with a C20-C24 hydrocarbyl substituent. Once
such
internal olefin sulfonate for the FDP process as a preferred embodiment is
EnordetTM
0242 as manufactured by Shell Chemicals.
100901 In S345,
the concentrations of the components of the foam are selected
based on the reservoir conditions and process conditions at the time of FDP
deployment. For example, if the native bitumen is particularly viscous, more
steam
may be added to the FDP mix to provide additional latent heat for heating of
the
bitumen.
100911 One non-
limiting exemplary formulation for a conventional SAGD
process followed by a propane-based solvent-driven process followed by a FPD
may
including using: propane as the gas-phase component accounting for about 60 %
of
the foam on a mass basis; heated water at 90 C as the liquid phase component
accounting for about 10 % of the foam on a mass basis; steam accounting for
about
30 % of the foam on a mass basis and EnordetTm 0242 as manufactured by Shell
Chemicals as the surfactant accounting for about 1,000 to 5,000 ppm of the
foam on
a mass basis.
[0092] Another
non-limiting exemplary formulation for a conventional SAGD
process followed by a propane-based solvent-driven process followed by a FDP
may
including using a foam formulation of propane as the gas-phase component,
heated
water and/or condensed steam as the liquid phase component, and EnordetTM 0242
as manufactured by Shell Chemicals as the surfactant. In particular, the
formulation
may be prepared from a mixture of 80 % solvent, 20 % steam/heated water at 110
C, and 1,000 to 5,000 ppm surfactant (all values provided on a mass basis).
[0093] In S350,
the conditions for switching to the FDP are selected. Transition
conditions may be selected such as to, for example, achieve a desirable
balance
between various factors and considerations including engineering trade-offs
and
economic considerations, such as vapor chamber growth, production performance,
costs, and environmental factors. The transition condition may be selected to
ensure
CA 3030920 2019-01-18
that the performance threshold discussed earlier has been reached. The
transition
condition may be selected based on operational experience in similar projects
at other
well pads, or projections according to modeling or simulation calculations, or
a
combination thereof. The transition condition may also be adjusted or selected
based
on the market conditions including production costs, material costs, and the
market
values of produced or recovered materials including market oil prices and
solvent
prices.
[0094] Briefly stated, the FDP S360 should be initiated at a time
that minimizes
the SvOR. To minimize the SvOR the FDP S360 should be initiated after
determining
that a suitable transition condition has been met (S355) The following trigger
points
may be used to select the transition conditions and to determine that a
suitable
transition condition has been met (S355) with the result of the FDP being a 5%
or
greater decrease in the SvOR.
Trigger Point 1 ¨ Produced Solvent Becomes Excessive
[0095] In select embodiments, the FDP S360 is initiated when the ratio of
produced solvent to injected solvent becomes greater than 40 mass % for at
least
two weeks on a continuous basis. A "spike" of produced solvent should not
count
towards this calculation as it could be a short lived operations related
effect. The
rationale for this trigger is that when the produced solvent is greater than
40 mass %
of the injected solvent, the process in the reservoir is becoming inefficient
(gas cycling
is excessive). The produced solvent may be in the gas phase, in an emulsion,
or
combinations thereof.
[0096] The produced solvent to injected solvent ratio is an exact
measurement.
Both the produced solvent and the injected solvent may be directly measured in
the
field.
Trigger Point 2 ¨ Solvent Saturation in the Reservoir Becomes Excessive at the
Chamber's Edge
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CA 3030920 2019-01-18
[0097] In select embodiments, the FDP S360 is initiated when the
solvent
saturation becomes too high at the edge of the chamber. Too high may be
defined
as a 60% solvent saturation in the vapor phase just before the solvent
condenses as
part of the SDRP recovery process. Measuring the solvent concentration at that
particular point is very difficult, if not impossible, because the process is
in situ.
However, the solvent concentration can be measured indirectly / estimated. In
particular, the composition of the produced gas and the amount of solvent
dissolved
in the production fluid can be used as a proxy for the solvent concentration ¨
the
higher the mass fraction of solvent in the produced gas, the higher the
solvent
concentration in the reservoir just prior to the point of condensation. The
maximum
amount of solvent that can be dissolved in the production fluid is a function
of the
solvent solubility and is quite low (e.g. 10-15 % on a mass basis) when
compared to
the amount of solvent produced in the gas phase (e.g. 85-90 `)/0 on a mass
basis). So,
the amount of solvent in the gas phase is used for this measure. For this
trigger, when
the composition of the produced gas becomes greater than 75 mol %, the FDP
should
be initiated.
Trigger Point 3 ¨ Time / Progress Based: Start FDP after SDRP has Operated for
a
Fixed Period or Based on Reservoir Estimation Methods
[0098] In select embodiments, the FDP S360 is initiated after 25% of
the
estimated well life under SAP. For example, if the reserves for a well pair
during the
SDRP phase (not including the SAGD rise rate phase) is 100 m3, the FDP S360
should be initiated when d25 m3 (or 25%) of the reserves are produced.
Determining
an estimated recoverable hydrocarbon reserve may be done by any method known
to those skilled in the art. Exemplary methods for determining an estimated
recoverable hydrocarbon reserve include, but are not limited to reservoir
simulation,
decline analysis, material balance, or combinations thereof.
[0099] In alternate embodiments, S340, S345, S355, and S360 are
applied to
single well configurations. The application of S340, S345, S355, and S360 to a
single
32
CA 3030920 2019-01-18
well configuration are within the purview of those skilled in the art having
regard to
the present disclosure and will not be set out in detail.
[00100] The operation may enter an ending or winding down phase, at
S365,
with a process known as a blowdown stage. The blowdown stage S365 may be
performed in a similar manner as in a conventional SAGD process. During the
blowdown phase S365, a non-condensable gas may be injected into the reservoir
100 to displace steam or the solvent. For example, the non-condensable gas may
be
methane.
[00101] Alternatively, in an embodiment, the solvent used for
injection in the
solvent-driven process and the foam displacement stage S360 may be
continuously
utilized through a blowdown phase, in which case it is possible to eliminate
or reduce
injection of methane during blowdown. In particular, it is not necessary to
implement
a conventional blowdown phase with injected methane gas, when a significant
portion
of the injected solvent can be readily recycled and reused. For example,
injected
methane or other NCG may mobilize gaseous solvent in the chamber to facilitate
removal of the solvent.
[00102] During the blowdown stage S365, oil recovery or production may
continue with production operations being maintained. When methane is used for
blowdown, oil production performance will decline over time as the growth of
the
vapor front in the vapor chamber 260 slows under methane gas injection.
[00103] In an embodiment of the present process, at the end of the FDP
S360,
the injection well 120 may be shut in, but solvent (and some production fluid)
recovery
may be continued and followed by methane injection to enhance solvent
recovery.
The production fluid may be produced until further recovery of fluids from the
reservoir
is no longer economical (e.g. when the recovered oil no longer justifies the
cost for
continued production, including the cost for solvent recycling and re-
injection).
33
CA 3030920 2019-01-18
[00104]
In alternate embodiments, S365 is applied to single well configurations.
The application of S365 to a single well configuration is within the purview
of those
skilled in the art having regard to the present disclosure and will not be set
out in
detail.
[00105] Turning
now to FIG. 4, The Applicant has completed simulations that
indicate that at least about 15 % of the volume of the chamber should be taken
up by
foam in order to obtain a SvOR that is reduced by at least about 5 %. In FIG.
4, a
foam accumulation zone is shown in a hydrocarbon-depleted interior region of
the
vapor chamber, and a high solvent content zone is shown in an exterior region
of the
vapor chamber.
[00106]
Laboratory studies to evaluate foam generation in porous media for
oilfield applications generally involve the study of (capillary) snap-off,
lamella division
and foam leave behind. These studies also generally include experiments to
analyze
foam destruction which include capillary-suction coalescence and gas diffusion
through microscopic studies of foam using micro-models. In mechanistic models,
the
rates of foam generation and destabilization are defined to replicate the
process that
is observed in the lab.
[00107]
In simulation the mechanistic model that is suggested for use in more
complex foam processes is to define "lamella" as a true membrane based lamella
component and "foam gas" as a gaseous component. In CMG-STARS simulation the
reactions are defined to model foam generation and foam collapse. The
reactions are
defined to implement each of the mechanisms. Mechanistic rate equations for
the
generation of foam by capillary snap-off and capillary suction coalescence are
modelled to match the results from foam height test and core-flooding tests.
The best
techniques to evaluate the foamability and foam stability of the surfactant
are foam
height test and core-flooding tests with foam. The simulation model needs to
be
calibrated with test data from the foam height test and core-flooding tests.
34
CA 3030920 2019-01-18
[00108] In the simulation reactions, the lamella/aqueous phase is
assumed
incompressible and non-volatile, while the foam gas (i.e., solvent vapour) is
assumed
insoluble and ideal. The mechanisms controlling transport and mobility of foam
are
controlled by the apparent viscosity assigned to the gas viscosity of
"lamella" and
"foam gas".
[00109] The optimum foam for the FDP of the present disclosure is a
weak foam
(in the 20% foam quality range). A weak foam is desirable for at least two
reasons. A
first reason that a weak foam is desirable for the present disclosure is that
weak foams
have lower mobility reduction factor (MRF). A lower MRF allows for easier
injection
into the chamber. The low MRF foam will follow the path of least resistance,
which is
to the center of the chamber where it is desired. A second reason that a weak
foam
is desirable for the present disclosure is that weak foams will tend to
coalesce and
collapse readily in the center of the chamber. This may lead to the gas phase
component of the solvent diffusing out to the chamber edge where it may
mobilize
heavy hydrocarbons. This is depicted in FIG. 4 by a wavy arrow showing
"solvent
vapor" diffusion. Collapse forces the solvent, which was used to create the
foam in
the first place to squeeze outwards (depicted as solvent vapor in the picture
above).
[00110] FIG. 5 provides simulation data showing foam mobility
reduction factor
as a function of foam quality. As seen in FIG. 5, the viscosity of foam
increases with
.. increasing quality up to an undefined critical flow rate. The viscosity of
foam becomes
constant for all values of flow rate above a critical flow rate. The foam
quality ( F ) is
given by:
F = Vfoam gas
Vfoam gas + Vlamella
CA 3030920 2019-01-18
[00111]
where Vfoam gas is foam gas volume, and Vlamella is lamella (the liquid
phase) volume. As mentioned, low quality foams provide lower MRF and lower
foam
mobility reduction potential. The mobility reduction factor (MRF) is given by:
MRF = APf
A Pst
[00112]
where A Pf is steady state pressure drop across the area of
examination (e.g. in a lab setting this would be a reservoir core flood) with
foam
injection, and A Pst is the steady state pressure drop across the core flood
with steam
only injection at rates equivalent to those in the foam injection test.
[00113]
A comparison of the variation of solvent within an SDRP chamber with
foam injection vs. regular SDRP (without foam injection) is provided by
comparing
FIG. 6 and FIG. 7. FIG. 6 shows an example high MRF foam injection case (at
high
foam quality) vs. an SDRP only case. FIG. 7 shows an example low MRF foam
injection case (at low foam quality) vs. an SDRP only case. As can be seen,
the
solvent edge is thicker and the solvent/bitumen mixing zone is greater in both
the
high quality foam injection case and the low quality foam injection case
versus the
SDRP only cases. Since, in select embodiments the gas-phase component in the
foam injection cases is the same solvent used in the SDRP process, any portion
of
the gas-phase component that is leaked away from the foam rich interior of the
chamber due to foam collapse will move to the edges of the chamber where it
may
facilitate mobilization of heavy hydrocarbons. This is shown with a wavy line
in FIG
4. As shown in FIG.7, injecting a lower quality foam forces the solvent to
move more
to the edges of the SDRP chamber due to its larger foam front growth relative
to the
higher quality foam injection case of FIG. 6. This may be best seen in FIG. 8
provides
low/high quality foam injection results of FIG. 6 and FIG. 7 in the same
diagram.
[00114] The primary concern with higher quality foam injection is that
foam will
penetrate to the edge of the steam chambers where oil drainage occurs. Due its
high
36
CA 3030920 2019-01-18
mobility reduction factor, high quality foam will reduce overall mobility so
much that
the overall injection rate into the well will be reduced so significantly,
with a
consequence of a reduced oil production rate. Foam injection from a tertiary
well (i.e.
a horizontal well, a vertical well, or slanted well that is in addition to the
well pair) is
one means for addressing this issue. The variation of solvent content within
the SDRP
chamber after foam injection from a vertical tertiary well is exemplified by
FIG. 9. As
shown, the solvent variation at the edge of the chamber with top foam
injection from
the vertical well (right panel) is somewhat similar to the variation at the
edge of the
chamber with bottom foam injection from the horizontal well (left panel).
[00115] FIG. 10 provides simulation data showing solvent and foam
accumulation within a chamber for an example FDP based on high quality foam
(left
panel) vs. low quality steam injection (right panel). The example on the left
panel
shows a large high solvent content zone while the steam process of the right
panel
shows a lower high solvent content zone with an area of water accumulation in
the
middle of the chamber.
[00116] FIG. 11 provides simulation data as a plot of cumulative oil
production
as a function of time after operation for an example low quality steam
injection case,
an example foam injection from a vertical well case, and an SDRP only case. It
is
clear from inspection that cumulative oil production is not significantly
influenced by
foam injection from a vertical well relative to low quality steam injection or
SDRP only.
[00117] FIG. 12 provides simulation data as a plot of cumulative oil
production
as a function of time after operation for an example high quality foam
injection case
and an example low quality foam injection case as compared to an SDRP only
case.
It is clear that the high quality foam injection case produces a similar
volume of oil to
the SDRP case. Low quality foam injection produces slightly less oil
production than
the SDRP process.
[00118] FIG. 13 provides simulation data as a plot of cumulative
solvent
injection on a gas phase basis as a function of time after operation for an
example
37
CA 3030920 2019-01-18
high quality foam injection case and an example low quality foam injection
case as
compared to an SDRP only case. It is clear that when foam injection starts, at
approximately 3.5 years, that the volume of gas injection for both the high
quality and
the low quality foam injection is substantially lower than for the straight
SDRP case.
[00119] An important drawback of using the straight SDRP process (no foam
injection) is the large amount of solvent that is required for a given
produced oil
volume. As demonstrated in FIG. 13, when foam injection starts, the rate of
increase
of the volume of solvent injected drops considerably compared to the SDRP
case.
For the SDRP case, the solvent that needs to be continuously injected is a
tremendous burden on the economics of the process. Not only does a significant
amount of expensive solvent need to be purchased, but recycling the produced
solvent back into the same injector is costly, labour intensive and can become
contaminated with other reservoir gasses like methane. This drawback is one of
the
key factors that has limited the implementation of SDRP processes in the past.
[00120] An important benefit of the FDP described herein is that the
injected
foam significantly reduces the amount of solvent required for a similar volume
of
produced oil. For example, it is seen in FIG. 13 that the amount of cumulative
solvent
injected for the high foam quality and low foam quality is significantly less
than for the
straight SDRP case.
[00121] As demonstrated for the low foam quality case, oil production is
slightly
reduced compared to the straight SDRP case (as seen in FIG. 12). However, the
economic value of the significantly reduced amount of solvent required for the
low
foam quality injection case may be significantly greater than the reduced oil
volume
that is produced from the process.
[00122] This point is illustrated in FIG. 14 which presents the solvent-oil-
ratio
(SvOR) which is calculated by taking the amount of cumulative solvent injected
(on a
liquid equivalent basis; e.g. bbl.'s) divided by the cumulative volume of oil
produced
(volume basis; e.g. bbl.'s). The SvOR is shown for the SDRP case and the low
and
38
CA 3030920 2019-01-18
high quality foam injection cases in FIG. 14 shows that as soon as foam
injection
starts, the amount of solvent required to produce a barrel of oil starts to
drop
significantly. This drop shows the economic value of the FDP process.
It can been seen that, in select embodiments, the foam injection cases, like
high foam
quality injection may be adapted to be better than the straight SDRP process
in terms
of solvent injection requirements, whereas the low foam quality case may be
adapted
to provide improved results.
FIG. 15 shows the variation of foam quality after increasing the foam
injection
pressure. It is evident that as the injection pressure is increased that the
foam quality
goes down. Generally speaking, foam significantly reduces the mobility of
reservoir
fluids surrounding the injector only, meaning operators can increase the
injection
pressure without fear of the high pressures reaching the caprock or to top
water
zones. High pressure promotes the foam propagation within the core of the
chamber,
forcing solvent to the edge of the chamber, improving the oil production rate
and
solvent recovery. Higher pressure also reduces the foam quality which further
helps
the foam transport within the core of the SDRP chamber. Since the injected
foam is
mostly gas, the foam is compressible and thus Boyle's law can be applied
directly to
the foam, neglecting gas solubility in the solution and liquid expansion. Raza
and
Marsden (1967) present the following equation for predicting foam quality at
pressures higher than the initial injection pressure:
1
F = (
P 1
1 + 1
Pa Fa
[00123]
where F is the calculated foam quality at pressure P, and Fa is the
injected foam quality at pressure Pa. FIG. 15 shows the variation of foam
quality with
increasing pressure greater than the initial foam injection pressure. As
shown,
increasing the pressure from 3,250 to 7,000 kPa results in a reduction in foam
quality
39
CA 3030920 2019-01-18
of around 10%. Overall, the higher injection pressures will help solvent
recovery due
to improvement in foam propagation within the core of the SDRP chamber.
[00124] In simulation, the effect of higher injection pressure should
implemented
in the "lamella" and "foam gas" viscosity reduction. It must be noted that the
viscosity
of foam increases with increasing quality up to an undefined critical flow
rate. The
critical flow rate is never reached with porous media. It is a concept mostly
defined
for pipe hydraulics.
CA 3030920 2019-01-18
