Note: Descriptions are shown in the official language in which they were submitted.
CA 02898943 2015-07-30
=
METHODS OF PERFORMING CYCLIC HYDROCARBON PRODUCTION
PROCESSES
FIELD OF THE DISCLOSURE
The present disclosure is directed to methods of performing cyclic hydrocarbon
production processes.
BACKGROUND OF THE DISCLOSURE
Cyclic solvent processes (CSP) may be utilized to decrease a viscosity of
viscous
hydrocarbons, such as bitumen, which may be present within a subterranean
formation, thereby
permitting production of the viscous hydrocarbons from the subterranean
formation via a
hydrocarbon well. CSP may be attractive due to relatively low greenhouse gas
emissions
intensity, which may be defined as tons carbon dioxide emitted per cubic meter
of bitumen
produced, associated with CSP. In addition, CSP may be utilized to produce
viscous
hydrocarbons from subterranean formations that may not be readily amenable to
other
stimulation techniques.
However, traditional CSP generally forms two phase-separated liquid phases
within the
subterranean founation. These two phase-separated liquid phases include a
light phase, which is
diluent-rich and includes relatively lighter fractions of the bitumen (i.e., a
light liquid
hydrocarbon), and a heavy phase, which includes relatively heavier fractions
of the bitumen,
including asphaltenes (i.e., a heavy liquid hydrocarbon). The heavy phase has
a relatively higher
viscosity and may face difficulty flowing out from the subterranean formation,
may overload
pumps that may be utilized to produce the viscous hydrocarbons from the
subterranean
formation, and/or may plug various components of the hydrocarbon well and/or
of surface
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CA 02898943 2015-07-30
facilities that support the hydrocarbon well. In addition to founing two
liquid phases, traditional
CSP may suffer from hydrate formation that may adversely affect the production
of
hydrocarbons.
To mitigate these issues, a significant portion of the heavy phase, which may
account for
approximately 70% of the viscous hydrocarbons, may be left within the
subterranean formation,
thereby significantly decreasing overall hydrocarbon production from a given
subterranean
formation. Thus, there exists a need for improved methods of performing cyclic
hydrocarbon
production processes.
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CA 02898943 2016-02-23
SUMMARY
Certain exemplary embodiments provide a method of performing a cyclic
hydrocarbon
production process to stimulate production of viscous hydrocarbons from a
subterranean
formation, the method comprising: injecting a diluent into the subterranean
formation to dilute
the viscous hydrocarbons and generate reduced-viscosity hydrocarbons within
the subterranean
formation, wherein the reduced-viscosity hydrocarbons include a diluted
viscous hydrocarbon
fraction; subsequent to the injecting the diluent, producing a product
hydrocarbon stream from
the subterranean formation, wherein the product hydrocarbon stream includes at
least a portion
of the reduced-viscosity hydrocarbons; monitoring a variable of the product
hydrocarbon stream
that is indicative of the diluted viscous hydrocarbon fraction; and adjusting
at least one property
of the diluent to define a modified diluent and to mitigate formation of a
heavy liquid
hydrocarbon fraction within the subterranean formation, wherein the adjusting
is based, at least
in part, on the variable of the product hydrocarbon stream; wherein, prior to
the injecting the
diluent, the method further includes characterizing the viscous hydrocarbons
wherein the
characterizing the viscous hydrocarbons includes determining a critical
diluent-to-viscous-
hydrocarbon ratio for dilution of the viscous hydrocarbons by a given diluent
at a given
temperature and a given pressure; and when the given diluent and the viscous
hydrocarbons are
mixed at a ratio that is less than the critical diluent-to-viscous-hydrocarbon
ratio, the given
diluent and the viscous hydrocarbons combine to generate a single liquid phase
that includes the
diluted viscous hydrocarbon fraction.
Other exemplary embodiments provide a method of performing a cyclic
hydrocarbon
production process to stimulate production of viscous hydrocarbons from a
subterranean
formation, the method comprising: determining a critical diluent-to-viscous-
hydrocarbon ratio
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CA 02898943 2016-02-23
for dilution of the viscous hydrocarbons by a diluent at a given temperature
and pressure;
calculating a quantity of heat required to heat a portion of the subterranean
formation to the
given temperature; providing the quantity of heat to the subterranean
formation to heat the
subterranean formation to the given temperature; injecting a predetermined
volume of the diluent
into the subterranean formation to dilute the viscous hydrocarbons and
generate reduced-
viscosity hydrocarbons within the subterranean formation; ceasing the
injecting the diluent;
subsequent to the ceasing the injecting, producing a product hydrocarbon
stream from the
subterranean formation, wherein the product hydrocarbon stream includes at
least a portion of
the reduced-viscosity hydrocarbons; concurrently with the producing,
regulating a production
pressure of the product hydrocarbon stream to maintain the production pressure
above a
threshold production pressure; concurrently with the producing, monitoring a
variable of the
product hydrocarbon stream that is indicative of a diluted viscous hydrocarbon
fraction of the
product hydrocarbon stream; ceasing the producing responsive to a temperature
of the product
hydrocarbon stream being at least one of less than a lower stream temperature
threshold and
lower than a hydrocarbon stream production rate threshold; adjusting at least
one property of the
diluent to define a modified diluent and to mitigate formation of a heavy
liquid hydrocarbon
fraction within the subterranean formation, wherein the adjusting is based, at
least in part, on the
variable of the product hydrocarbon stream; and repeating at least the
calculating, the providing,
the injecting, the ceasing the injecting, the producing, the regulating, the
monitoring, the ceasing
the producing, and the adjusting a plurality of times as part of a plurality
of stimulation-
production cycles.
Methods of performing cyclic hydrocarbon production processes are disclosed
herein.
The methods include injecting a diluent into a subterranean formation to
dilute viscous
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CA 02898943 2016-02-23
hydrocarbons that are present within the subterranean formation and to thereby
generate reduced-
viscosity hydrocarbons. The methods further include producing a product
hydrocarbon stream
from the subterranean formation and monitoring a variable of the product
hydrocarbon stream
that is indicative of a diluted viscous hydrocarbon fraction of the viscous
hydrocarbons. The
methods also include adjusting at least one property of the diluent to define
a modified diluent.
The adjusting is based, at least in part, on the variable of the product
hydrocarbon stream, and the
adjusting includes adjusting to mitigate formation of a heavy liquid
hydrocarbon fraction within
the subterranean formation.
The methods further may include determining a critical diluent-to-viscous-
hydrocarbon
ratio for dilution of the viscous hydrocarbons by the diluent at a given
temperature and a given
pressure. The methods also may include calculating a quantity of heat required
to heat a portion
of the subterranean formation to the given temperature and providing the
quantity of heat to the
subterranean formation. Injecting the diluent may include injecting a
predetermined volume of
the diluent. The methods further may include ceasing the injecting prior to
the producing. The
methods also may include regulating a production pressure of the product
hydrocarbon stream
during the producing. The methods further may include ceasing the producing
responsive to a
temperature of the product hydrocarbon stream being less than a lower stream
temperature
threshold. The methods also may include repeating at least a portion of the
methods as part of a
plurality of stimulation-production cycles.
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BRIEF DESCRIPTION OF THE DRAWINGS
Fig. 1 is a schematic side view of a hydrocarbon well that may be operated
utilizing the
methods according to the present disclosure.
Fig. 2 is a schematic cross-sectional view of a portion of the hydrocarbon
well of Fig. 1.
Fig. 3 is another schematic cross-sectional view of the portion of the
hydrocarbon well of
Fig. 1.
Fig. 4 is a bar chart illustrating relative volume fractions of light liquid
hydrocarbon,
heavy liquid hydrocarbon, and/or diluted viscous hydrocarbons for a sample of
bitumen.
Fig. 5 is a ternary phase diagram illustrating phase-behavior of a mixture of
bitumen,
methane, and propane.
Fig. 6 is a ternary phase diagram illustrating phase-behavior of a mixture of
bitumen,
methane, and dimethyl ether.
Fig. 7 is a plot of hydrocarbon recovery as a function of injected diluent
volume for
several different diluents.
Fig. 8 summarizes the results of a simulation in which several stimulation-
production
cycles were performed utilizing two different cyclic stimulation processes.
Fig. 9 is a flowchart depicting methods, according to the present disclosure,
of
performing a cyclic stimulation process.
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DETAILED DESCRIPTION
Fig. 1 is a schematic side view of a hydrocarbon well 50 that may be operated
utilizing
the methods according to the present disclosure. Hydrocarbon well 50 includes
a wellbore 52
that extends within a subterranean formation 40. Subterranean formation 40 may
be present
within a subsurface region 30, and wellbore 52 may extend between a surface
region 20 and the
subterranean formation 40. Subterranean formation 40 includes viscous
hydrocarbons 42, and
hydrocarbon well 50 may be configured to produce the viscous hydrocarbons from
the
subterranean formation and/or to convey the viscous hydrocarbons to the
surface region utilizing
the methods disclosed herein.
During operation of hydrocarbon well 50, a diluent stream 60, which includes a
diluent
62, may be supplied to subterranean formation 40, such as via wellbore 52. The
diluent stream
may be supplied for, or during, a supply time interval as part of a
stimulation cycle. Diluent
stream 60 and/or diluent 62 thereof may physically contact and/or dilute
viscous hydrocarbons
42 within a diluent chamber 80 that extends proximal to wellbore 52 and within
the subterranean
formation 40. This dilution of the viscous hydrocarbons 42 by diluent 62 may
generate reduced-
viscosity hydrocarbons 44, which may have a lower viscosity than viscous
hydrocarbons 42.
Subsequently, supply of the diluent stream may be stopped and a product
hydrocarbon
stream 70 may flow, or be flowed, from subterranean formation 40 via wellbore
52. The product
hydrocarbon stream may be produced for a production time interval and/or as
part of a
production cycle. The production may include flow of the product hydrocarbon
stream from
subsurface region 30 to surface region 20. The supply of diluent stream 60
(i.e., the stimulation
stage), followed by the production of product hydrocarbon stream 70 (i.e., the
production stage),
may be repeated any suitable number of times as part of a cyclic stimulation
process and/or a
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CA 02898943 2015-07-30
cyclic hydrocarbon production process according to the present disclosure. A
corresponding pair
of stimulation and production stages may be referred to herein as a
stimulation-production cycle,
and/or as a hydrocarbon production cycle. The repeating also may be referred
to herein as
performing a plurality of stimulation-production stages and/or as performing a
plurality of
stimulation-production cycles.
Product hydrocarbon stream 70 may include a plurality of components, including
some of
the injected diluent 62, water from subterranean formation 40, diluted viscous
hydrocarbons 72,
a light liquid hydrocarbon 74, and/or a heavy liquid hydrocarbon 76. Reduced-
viscosity
hydrocarbons 44 may include diluted viscous hydrocarbons 72 and/or light
liquid hydrocarbon
74. As discussed in more detail herein, combination of diluent 62 with viscous
hydrocarbons 42
under certain environmental conditions and/or at certain ratios of diluent 62
to viscous
hydrocarbons 42 may cause diluent 62 to be absorbed into and/or to dilute the
viscous
hydrocarbons 42, thereby generating diluted viscous hydrocarbons 72. Diluted
viscous
hydrocarbons 72, at least when formed, may be a single liquid phase that
comprises diluent 62
and viscous hydrocarbons 42, and the single liquid phase may have a distinct
density and
viscosity compared to the diluent and viscous hydrocarbons from which the
phase is fonned.
Such environmental conditions may be referred to herein as a dilution regime
(i.e., as a regime in
which the viscous hydrocarbons are diluted by the diluent). As discussed in
more detail herein,
the environmental conditions may include, but are not limited to, diluent
type, diluent
composition (if diluent is a mixture of more than one diluent), diluent-to-
viscous- hydrocarbons
ratio, relative concentration of non-condensable gas (e.g., nitrogen, methane,
or CO2) relative to
diluent and/or to viscous hydrocarbons, non-condensable gas compositionõ
temperature, and/or
pressure.
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In contrast, and as also discussed in more detail herein, combination of
diluent 62 with
viscous hydrocarbons 42 under other (i.e., different) environmental conditions
and/or at other
ratios may cause the diluted viscous hydrocarbons to phase-separate into light
liquid
hydrocarbons 74, which comprise lighter fractions of viscous hydrocarbons 42
and diluent 62,
and is diluent-rich, and heavy liquid hydrocarbons 76, which comprise heavier
fractions of
viscous hydrocarbons 42 and diluent 62, and is diluent-lean. The environmental
conditions may
again include, but not limited to, those discussed above in connection with
the foiniation of
diluted viscous hydrocarbons 72. Such environmental conditions may be referred
to herein as a
viscous region. The systems and methods disclosed herein may be configured to
increase
formation of diluted viscous hydrocarbons 72 and/or to decrease, or mitigate,
formation of light
liquid hydrocarbons 74 and heavy liquid hydrocarbons 76.
As a more specific example, the methods disclosed herein may include
determining a
critical diluent-to-viscous-hydrocarbons ratio for dilution of viscous
hydrocarbons 42 by diluent
62 at a given temperature and a given pressure. Subsequently, a quantity of
heat required to heat
a portion of subterranean formation 40, such as a portion of diluent chamber
80, to the given
temperature may be calculated. The quantity of heat then may be provided to
the portion of the
subterranean formation, such as via a heat source 96, to heat the portion of
the subterranean
foimation to the given temperature. The heat source 96 may be and/or include
steam injected
before injecting diluent 62 to the near-wellbore region, heat provided to
diluent on the surface or
in wellbore 52, and/or electrical or electromagnetic heating of the near well-
bore region or
away-from-wellbore region. Away-from-wellbore region heating can be achieved
by drilling
lateral wells from the well 50 or wellbore 52. Once the portion of the
subterranean formation has
been heated to the given temperature, a predeteiiiiined volume of diluent 62
may be injected into
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CA 02898943 2015-07-30
the subterranean formation as part of a stimulation cycle. Diluent 62 may
dilute viscous
hydrocarbons 42, as discussed herein, and the predeteimined volume of the
diluent may be
selected to maintain a diluent-to-viscous-hydrocarbons ratio within the
portion of the
subterranean formation below a critical diluent-to-viscous hydrocarbons ratio,
thereby
preferentially generating diluted viscous hydrocarbons 72 over light liquid
hydrocarbons 74 and
heavy liquid hydrocarbons 76. Some examples of the diluent-to-viscous-
hydrocarbon ratio and
the critical diluent-to-viscous-hydrocarbon ratio, which depend on the diluent
and the viscous
bitumen, are disclosed herein, including in connection with Figs. 4-6.
The methods may further include injecting a non-condensable gas, such as
nitrogen,
methane, or carbon dioxide, or a mixture thereof, with the diluent to achieve
a diluent-to-
viscous-hydrocarbon ratio that is below the critical diluent-to-viscous-
hydrocarbon ratio. The
incorporation of the non-condensable gas lowers the diluent proportion in the
pore space
containing the viscous hydrocarbons, thereby lowering the diluent to viscous
hydrocarbons to
less than the critical diluent-to-viscous-hydrocarbons ratio. This may be
advantageous in later
cycles of the stimulation-production process, when the proportion of viscous
hydrocarbons in the
pore spaces is lower than that in early cycles. Lowering the ratio of diluent
to viscous
hydrocarbons means lowering the ratio to be less than the critical diluent to
viscous
hydrocarbons, thereby enabling the process to be in the dilution regime, where
a single phase of
diluted viscous hydrocarbons exists.
The diluent injection then may be stopped, and product hydrocarbon stream 70
may be
produced from the subterranean formation as part of a production cycle.
Concurrently with
production of the product hydrocarbon stream, a production pressure of the
product hydrocarbon
stream may be controlled and/or regulated to maintain the production pressure
above a threshold
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production pressure. Also concurrently with production of the product
hydrocarbon stream, a
variable of the product hydrocarbon stream may be monitored. The variable of
the product
hydrocarbon stream may be indicative of a diluted viscous hydrocarbon fraction
of the product
hydrocarbon stream. Production of the product hydrocarbon stream may be
stopped and/or
ceased responsive to a temperature of the product hydrocarbon stream being
less than a stream
temperature threshold. Production of the product hydrocarbon stream also may
also be stopped ,
and/or ceased responsive to a product hydrocarbon production rate being less
than a product
hydrocarbon production rate threshold.
The production cycle may be assessed to compare a composition of the product
hydrocarbon stream to a desired, or target, composition of the product
hydrocarbon stream.
Then, at least one property of the diluent may be adjusted to define a
modified diluent. The
adjustment may be made to mitigate fonnation of a heavy liquid hydrocarbon
fraction within the
subterranean formation and may be based, at least in part, on the monitored
variable of the
product hydrocarbon stream. At least a portion of the process then may be
repeated a plurality of
times as part of a plurality of stimulation-production cycles, thereby
expanding dilution chamber
80 and/or producing additional viscous hydrocarbons from the subterranean
formation.
As illustrated in dashed lines in Fig. 1, hydrocarbon well 50 may include
and/or be
associated with a detector 90, which may be configured to detect and/or
monitor the variable of
product hydrocarbon stream 70 and/or a variable that is associated with
hydrocarbon well 50.
Detector 90 may include and/or be any suitable detector that may be adapted,
configured,
designed, and/or constructed to detect any suitable variable. As examples,
detector 90 may
detect a temperature, a temperature associated with hydrocarbon well 50, a
temperature of
product hydrocarbon stream 70, a pressure, a pressure associated with
hydrocarbon well 50, a
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pressure within subterranean foimation 40, a pressure of product hydrocarbon
stream 70, a
chemical composition, a chemical composition associated with hydrocarbon well
50, a chemical
composition of product hydrocarbon stream 70, a viscosity, a viscosity
associated with
hydrocarbon well 50, a viscosity of product hydrocarbon stream 70, a density,
a density
associated with hydrocarbon well 50, a density of product hydrocarbon stream
70, a color, a
color of product hydrocarbon stream 70, a diluent-to-viscous-hydrocarbon ratio
in product
hydrocarbon stream 70, and/or a light liquid hydrocarbon to a heavy liquid
hydrocarbon ratio in
product hydrocarbon stream 70.
As also illustrated in dashed lines in Fig. 1, hydrocarbon well 50
additionally or
alternatively may include and/or be associated with heat source 96, which may
be configured to
directly and/or indirectly heat at least a portion of subterranean formation
40, such as diluent
chamber 80. Examples of heat source 96 include a combustion heater and/or an
electric heater.
Such a heater may be located in any suitable position and/or orientation
relative to hydrocarbon
well 50, such as at a surface region, in or along a vertical and/or horizontal
section of
hydrocarbon well 50, and/or extending within subterranean formation 40. As
also discussed,
heat source 96 may be a supply of steam or hot flue gas that is flowed into
the subterranean
formation to heat the subterranean foimation.
Subterranean formation 40 may include and/or be any suitable subterranean
formation
that includes viscous hydrocarbons 42. Examples of subterranean foimation 40
include an oil
sands formation, a heavy oil formation, a tar sands formation, a bituminous
sands formation,
and/or an oil shale formation. Similarly, viscous hydrocarbons 42 may include
and/or be any
suitable viscous hydrocarbons, examples of which include heavy oil, bitumen,
asphaltenes, tar,
and/or an unconventional hydrocarbon reserve.
CA 02898943 2015-07-30
,
Diluent 62 may include and/or be any suitable chemical that may combine and/or
mix
with viscous hydrocarbons 42 to generate product hydrocarbon stream 70, such
as diluted
viscous hydrocarbons 72, light liquid hydrocarbon 74, and/or heavy liquid
hydrocarbon 76. As
examples, diluent 62 may include methane, ethane, propane, butane, pentane,
hexane, heptane,
octane, nonane, decane, dimethyl ether, an alkane, cyclopentane, cyclohexane,
naphtha, natural
gas condensate, and/or gas plant condensate.
Figs. 2-3 are schematic cross-sectional views of a portion of hydrocarbon well
50 of
Fig. I. Figs. 2-3 illustrate wellbore 52 extending within subterranean
formation 40, which
includes viscous hydrocarbons 42. As discussed, and subsequent to supply of
diluent 62 to
subterranean formation 40, diluent chamber 80 may be formed within the
subterranean
formation. Diluent chamber 80 may include subterranean strata 88, such as
rock, sand, and/or
shale. Diluent 62 and/or viscous hydrocarbons 42 may be present within an
interstitial, or pore,
space within the subterranean strata, within which pore space water also may
be present.
As also discussed, the environmental conditions under which diluent 62 is
supplied to the
subterranean formation and/or the volume of diluent 62 that is supplied to the
subterranean
formation may change, vary, and/or dictate the manner in which diluent 62
interacts and/or
combines with viscous hydrocarbons 42 and/or may change, vary, and/or dictate
the material(s)
that are formed by the interaction and/or combination of the diluent with the
viscous
hydrocarbons.
As an example, and under a first set of environmental conditions and/or after
supply of a
first volume of diluent, diluent chamber 80 may have the material distribution
that is
schematically illustrated in Fig. 2. Therein, a diluent-rich region 82 extends
around and/or
proximal to wellbore 52. The diluent-rich region includes a high concentration
of diluent 62, and
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CA 02898943 2015-07-30
the diluent has displaced a significant portion of the viscous hydrocarbons
from the diluent-rich
region. Farther, or more distal, from the wellbore, a two-phase region 84
extends within the
subterranean formation. The two-phase region is formed via combination of
diluent 62 with
viscous hydrocarbons 42 and includes light liquid hydrocarbon 74 and heavy
liquid hydrocarbon
76, which may be phase-separated from one another. The conditions illustrated
in Fig. 2 are
common with conventional CSP, where the diluent chamber generally is flooded
with large
volumes of solvent. Under these conditions, it may be difficult to produce
heavy liquid
hydrocarbon 76 from the subterranean formation. In addition, heavy liquid
hydrocarbon 76
and/or one or more components that may be present therein may restrict fluid
flow within diluent
chamber 80, wellbore 52, well 50 or its associated pumps, pipes, or fittings,
thereby reducing
production of the viscous hydrocarbons from the subterranean formation.
Under a second set of environmental conditions and/or after supply of a second
volume
of diluent, diluent chamber 80 may have a material distribution that is
schematically illustrated in
Fig. 3. Therein, a diluent-rich region 82 extends around and/or proximal to
wellbore 52. As
illustrated, diluent-rich region of 82 of Fig. 3 may be smaller, or may
include a smaller volume,
when compared to diluent-rich region 82 of Fig. 2; however, this is not
required in all
embodiments. Similar to Fig. 2, the diluent-rich region of Fig. 3 includes a
high concentration of
diluent 62, and the diluent has displaced a significant portion of the viscous
hydrocarbons from
the diluent-rich region.
Farther, or more distal, from the wellbore, a two-phase region 84 extends
within the
subterranean formation. Similar to Fig. 2, the two-phase region of Fig. 3 is
formed via
combination of diluent 62 with viscous hydrocarbons 42 and includes light
liquid hydrocarbon
74 and heavy liquid hydrocarbon 76. Two-phase region 84 of Fig. 3 may be
smaller, or include a
CA 02898943 2015-07-30
smaller volume, when compared to two-phase region 84 of Fig. 2; however, this
is not required
in all embodiments.
Even farther, or more distal, from wellbore 52, a diluted viscous hydrocarbon
region 86
extends within the subterranean formation. The diluted viscous hydrocarbon
region may include,
or contain, diluted viscous hydrocarbons 72. It is within the scope of the
present disclosure that
diluted viscous hydrocarbons 72 also may be present under the conditions of
Fig. 2; however, a
volume of the diluted viscous hydrocarbon region may be significantly larger
under the
conditions of Fig. 3 when compared to the conditions of Fig. 2.
As discussed in more detail herein, the methods according to the present
disclosure may
be specifically designed and/or utilized to preferentially form, or increase
formation of, diluted
viscous hydrocarbon region 86 and/or diluted viscous hydrocarbons 72 within
diluent chamber
80. Additionally or alternatively, the methods according to the present
disclosure also may be
specifically designed and/or utilized to mitigate, or decrease, formation of
two-phase region 84
and/or of light liquid hydrocarbon 74 and heavy liquid hydrocarbon 76.
The preferential formation of diluted viscous hydrocarbon region 86 over, or
instead of,
two-phase region 84 may be accomplished in any suitable manner. As an example,
a volume of
diluent 62 that is supplied to the subterranean formation during a given
stimulation cycle may be
regulated and/or varied to cause preferential formation of the diluted viscous
hydrocarbon
region. As discussed in more detail herein, and under a given set of
environmental conditions, a
specific diluent may define a critical diluent-to-viscous-hydrocarbon ratio
with a given viscous
hydrocarbon. For such a system, combination of the diluent with the viscous
hydrocarbons at
less than the critical diluent-to-viscous-hydrocarbon ratio may generate
diluted viscous
hydrocarbons 72, while combination of the diluent with the viscous
hydrocarbons at greater than
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CA 02898943 2015-07-30
the critical diluent-to-viscous-hydrocarbon ratio may generate light liquid
hydrocarbon 74 and
heavy liquid hydrocarbon 76. As additional examples, a temperature within the
subterranean
formation, a pressure within the subterranean formation, and/or a chemical
composition of the
diluent may be varied to cause preferential fointation of the diluted viscous
hydrocarbon region.
Figs. 4-8 are more specific examples, in the fomi of experimental data,
illustrating
mechanisms by which formation of diluted viscous hydrocarbon region 86 may be
controlled
and/or regulated, thereby permitting preferential formation of diluted viscous
hydrocarbons 72
instead of, or in greater quantities than, light liquid hydrocarbon 74 and/or
heavy liquid
hydrocarbon 76. For each of Figs. 4-8, brief discussions of the experimental
conditions and the
experimental results are provided. The applicability of these experimental
results to control
and/or regulate the formation of diluted viscous hydrocarbons then is
discussed.
Fig. 4 is a bar chart illustrating relative volume fractions (as indicated on
the y-axis) of
light liquid hydrocarbon 74, heavy liquid hydrocarbon 76, and/or diluted
viscous hydrocarbons
72 for a sample of 35 weight percent propane (i.e., diluent) and 65 weight
percent Athabasca
bitumen (i.e., viscous hydrocarbons) that was combined in a phase-behavior
cell at various
temperatures (as indicated on the x-axis). Data were collected at 40 C, 70
C, and 90 C, and
the results were extrapolated to arrive at the data for 13 C and 102 C. The
viscosity of the
heavy liquid hydrocarbon was determined at each temperature. The results were
2708 centipoise
(cP) at 13 C, 261 cP at 40 C, 12 cP at 70 C, 3 cP at 90 C, and 0.9 cP at 102
C.
Fig. 4 illustrates that increasing the temperature of propane-bitumen mixture
increases the
volume percent of the heavy liquid fraction, with the mixture becoming a
single liquid phase
(i.e., diluted viscous hydrocarbons 72) at temperatures above 102 C. In
addition, increasing the
temperature also produces a significant decrease in the viscosity of the heavy
liquid hydrocarbon.
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These experimental results indicate that a portion, or fraction, of diluent
chamber 80 that
includes diluted viscous hydrocarbons 72 (as illustrated in Fig. 3) and/or a
portion, or fraction, of
product hydrocarbon stream 70 that includes the diluted viscous hydrocarbons
(as illustrated in
Fig. 1) may be increased by increasing the temperature within the subterranean
formation and/or
may be decreased by decreasing the temperature within the subterranean
fonnation.
Additionally or alternatively, these results indicate that a portion, or
fraction, of diluent chamber
80 that includes light liquid hydrocarbon 74 and/or heavy liquid hydrocarbon
76 and/or a
portion, or fraction, of product hydrocarbon stream 70 that includes the light
liquid hydrocarbon
and/or the heavy liquid hydrocarbon may be increased by decreasing the
temperature within the
subterranean formation and/or may be decreased by increasing the temperature
within the
subterranean foiniation. Additionally or alternatively, these results also
indicate that the
viscosity of product hydrocarbon stream 70 may be decreased by increasing the
temperature
within the subterranean formation and/or may be increased by decreasing the
temperature within
the subterranean formation.
Fig. 5 is a ternary phase diagram illustrating phase-behavior of a mixture of
Cold Lake
bitumen (Bitumen), methane (Cl), and propane (C3) at 5000 kilopascals and 20
C. Both
methane and propane are diluents that may be utilized with the methods
according to the present
disclosure. The phase diagram includes a liquid/vapor transition line 100 and
a single-
phase/two-phase liquid transition line 102 that together define four regions,
including a first
region 111, a second region 112, a third region 113, and a fourth region 114.
In first region 111, the mixture exists as a single liquid phase (i.e.,
diluted viscous
hydrocarbons 72 of Figs. 1 and 3). In second region 112, the mixture exists as
a single liquid
phase in equilibrium with a vapor phase. First region 111 and second region
112 together may
CA 02898943 2015-07-30
be referred to herein as a dilution regime for the ternary system (i.e.,
bitumen, C3, Cl) at 5000
kilopaseals and 20 C.
In third region 113, the mixture exists as two phase-separated liquid phases
(i.e., light
liquid hydrocarbon 74 and heavy liquid hydrocarbon 76 of Figs. 1-3). In fourth
region 114, the
mixture exists as two phase-separated liquid phases in equilibrium with a
vapor phase. Third
region 113 and fourth region 114 together may be referred to herein as a
viscous regime for the
ternary system (i.e., bitumen-C1-C3 system) at 5000 kilopascals and 20 C.
Fig. 5 illustrates that,
for the bitumen-C1-C3 system, the dilution regime is relatively small when
compared to the
viscous regime.
As discussed, conventional CSP generally operates in the viscous regime,
since,
historically, the assumption has been that providing additional solvent to the
subterranean
formation serves to dissolve additional viscous hydrocarbons, thereby
permitting production of
the additional viscous hydrocarbons. However, this assumption associated with
conventional
CSP may not necessarily be valid. For example, the solvent in CSP is not
really a solvent for
viscous hydrocarbons, as it dilutes, rather than dissolves, the viscous
hydrocarbons. Thus, the
so-called solvent in conventional CSP perhaps should be called a diluent that
dilutes viscous
hydrocarbons below a critical diluent to viscous hydrocarbons ratio and forms
two liquid phases,
one light and the other heavy, with the heavier phase having a higher
viscosity than the original
viscous hydrocarbons (on a diluent-free basis). Furthermore, the heavy liquid
phase that is
generated in the subterranean formation is difficult to produce from the
subterranean formation.
Hence, more solvent (actually diluent) is detrimental to viscous hydrocarbon
production, which
may explain why conventional CSP processes may have operated under the belief
that more
solvent (actually diluent) is better. In contrast, the methods disclosed
herein select the
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CA 02898943 2015-07-30
composition of the diluent, as well as relative proportions of methane,
propane, and bitumen
and/or other environmental conditions, such that the mixture is within the
dilution regime. Thus
a single liquid phase is generated, and this single liquid phase may more
readily be produced
from the subterranean formation, as its viscosity is lower than that of the
heavy liquid phase
Fig. 6 is a ternary phase diagram illustrating phase-behavior of a mixture of
Cold Lake
bitumen (Bitumen), methane (Cl), and dimethyl ether (DME) at 5000 kilopascals
and 20 C.
Both DME and methane are diluents that may be utilized with the methods
according to the
present disclosure. Similar to Fig. 5, the phase diagram includes a
liquid/vapor transition line
100 and a single-phase/two-phase liquid transition line 102 that together
define four regions,
including a first region 111, a second region 112, a third region 113, and a
fourth region 114.
The phase(s) that exist in each of the four regions may be at least
substantially similar to the
phase(s) that exist in the corresponding regions of Fig. 5.
The single-phase/two-phase transition line from Fig. 5 is illustrated in
dashed lines in Fig.
6, while the single-phase/two-phase transition line is shown by the solid
line. Fig. 6 clearly
illustrates a significant increase in the portion of the phase diagram that is
occupied by first
region 111 and second region 112, together constituting the dilution regime,
when compared to
the ternary system of Fig. 5. Thus, Fig. 6 illustrates that changes in the
chemical composition of
the diluent, such as by substituting DME for propane, can produce significant
changes in the
relative concentration ranges over which the single liquid phase exists.
Stated another way, the
single liquid phase exists over a significantly wider range of concentrations
in the ternary system
of Fig. 6 (i.e., Cl, DME, and Bitumen) when compared to the ternary system of
Fig. 5 (i.e., Cl,
C3, and Bitumen).
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As discussed, Figs. 5-6 include single-phase/two-phase liquid transition line
102. As also
discussed, the single liquid phase (i.e., diluted viscous hydrocarbons 72 of
Figs. 1 and 3) exists at
mixture compositions that are on one side of line 102 (i.e., within first
region 111 and/or second
region 112) and the two phase-separated liquid phases (i.e., light liquid
hydrocarbon 74 and
heavy liquid hydrocarbon 76) exist at mixture compositions that are on the
other side of line 102
(i.e., within third region 113 and/or fourth region 114).
Thus, line 102 may represent, describe, and/or quantify a critical diluent-to-
viscous-
hydrocarbon ratio for the indicated mixtures. Stated another way, when the
composition of the
mixture is such that the diluent-to-viscous-hydrocarbon ratio is greater than
the critical diluent-
to-viscous-hydrocarbon ratio (i.e., in regions 113 and/or 114), the diluent
and the bitumen
combine to generate the two phase-separated liquid phases. Conversely, when
the composition
of the mixture is such that the diluent-to-viscous-hydrocarbon ratio is less
than the critical
diluent-to-viscous-hydrocarbon ratio (i.e., in regions 111 and/or 112), the
diluent and the
bitumen combine to generate the single liquid phase.
For a binary system of a single diluent and a single viscous hydrocarbon, the
critical
diluent-to-viscous-hydrocarbon ratio may be a single ratio. As an example, the
critical diluent-
to-viscous-hydrocarbon ratio for the binary bitumen-propane (no Cl) system of
Fig. 5 is
approximately 35 volume percent. As another example, the critical diluent-to-
viscous-
hydrocarbon ratio for the binary bitumen-DME (no Cl) system of Fig. 6 is
approximately 52
volume percent.
Fig. 7 is a plot of viscous hydrocarbon recovery as a function of injected
diluent volume.
The data presented in Fig. 7 were collected in a sand pack that was saturated
with Cold Lake
bitumen at room temperature. The sand pack had a permeability of 5.4 Darcy.
During the
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CA 02898943 2015-07-30
experiments, three different diluents were tested. These diluents included
propane (which is
indicated at 120), DME (which is indicated at 122), and a mixture of 70%
propane and 30%
DME by volume (which is indicated at 124). For each test, a given diluent was
provided to the
sand pack at a constant rate of 2.7 mL/minute until the pressure reached 9.5
Megapascals
absolute pressure (MPaa). The given diluent then was supplied at a rate that
maintained the inlet
pressure at 9.5 MPaa. The amount of viscous hydrocarbon recovered from the
sand pack,
expressed as a percentage of the total amount of viscous hydrocarbon initially
present within the
sand pack, is plotted in Fig. 7 as a function of the number of pore volumes of
diluent supplied to
the sand pack for each of the three above-described diluent compositions. As
may be seen from
Fig. 7, the addition of DME, either alone or in combination with propane,
produces a significant
increase in the viscous hydrocarbon recovery for a given volume of diluent,
and the combination
of DME and propane, which is indicated at 124, produced the largest increase.
These experimental results suggest that performing cyclic solvent processes by
injecting
materials other than propane, which is the common injectant for prior art
processes, may have
the potential to significantly improve viscous hydrocarbon recovery. As an
example, the
combination of DME and propane increased viscous hydrocarbon recovery by 63%
after
injection of approximately 2.5 pore volumes when compared to a similar amount
of injected
propane alone.
Fig. 8 summarizes the results of a reservoir simulation in which several
stimulation-
production cycles were perfoinied utilizing two different cyclic stimulation
processes. In Fig. 8,
cumulative viscous hydrocarbon production is plotted as a function of time for
the two different
cyclic stimulation processes. For both cyclic stimulation processes, propane
was utilized as the
diluent. In a first cyclic stimulation process 130, the subterranean formation
was not heated over
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CA 02898943 2015-07-30
the course of the seven illustrated stimulation-production cycles. In a second
cyclic stimulation
process 132, the subterranean formation was not heated for the first four
stimulation-production
cycles, but a near-wellbore portion (50m x 20m x 100m) of the subterranean
formation was
heated prior to the start of a fifth stimulation-production cycle to a
temperature of 77 C by
adding 13076 GJ of heat energy, and then was not heated for the remaining
sixth and seventh
stimulation-production cycles. As illustrated clearly in Fig. 8, the addition
of heat during the
fifth stimulation-production cycle of second cyclic stimulation process 132
significantly
increased the cumulative viscous hydrocarbon production, and the positive
impact of the single
heating event was evident over the two subsequent stimulation-production
cycles (i.e., cycles 6
and 7). Fig. 8 further demonstrates that heat addition improves viscous
hydrocarbon production.
In experiments, it has been demonstrated that heat addition may increase
direct
greenhouse gas (GHG) intensity by only 14% while also reducing (direct and
indirect) GHG
intensity by 53%, with this significant reduction stemming from an almost
three fold increase in
bitumen production and only a 1.4 fold increase in GHG emission. Of this
increase, direct GHG
emission, such as results from burning natural gas to make steam at the
viscous bitumen
production site, may account for only 8% of the total GHG intensity. Indirect
GHG intensity
may result, for example, from emissions related to emissions while
manufacturing the diluent at
another site and transporting it to viscous hydrocarbon production site. Thus,
cyclic hydrocarbon
production methods according to the present disclosure may retain the low-GHG
attractiveness
of CSP while also decreasing the propensity for hydrate foimation compared to
traditional CSP.
Fig. 9 is a flowchart depicting methods 200, according to the present
disclosure, of
performing a cyclic stimulation process. The cyclic stimulation process may be
utilized to
stimulate production of viscous hydrocarbons from a subterranean formation.
Methods 200 may
CA 02898943 2015-07-30
include characterizing viscous hydrocarbons at 205, selecting a diluent
property at 210,
calculating a quantity of heat at 215, and/or heating the subterranean
formation at 220. Methods
200 include injecting diluent into the subterranean formation at 225 and may
include ceasing the
injecting at 230 and/or regulating a pressure at 235. Methods 200 further
include producing a
product hydrocarbon stream from the subterranean formation at 240 and may
include ceasing the
producing at 245. Methods 200 include monitoring a variable of the product
hydrocarbon stream
at 250 and adjusting at least one property of the diluent to define a modified
diluent at 255.
Methods 200 also may include repeating at least a portion of the (previously
performed) method
at 260.
Characterizing the viscous hydrocarbons at 205 may include characterizing any
suitable
property and/or parameter of the viscous hydrocarbons in any suitable manner
and may be
performed prior to the selecting at 210, prior to the heating at 220, and/or
prior to the injecting at
225. As an example, the characterizing at 205 may include obtaining a sample
of the viscous
hydrocarbons from the subterranean foimation and characterizing the sample of
the viscous
hydrocarbons. As another example, the characterizing at 205 may include
determining a critical
diluent-to-viscous-hydrocarbon ratio for dilution of the viscous hydrocarbons
by a given diluent
at given conditions, such as at a given temperature and/or at a given
pressure. As yet another
example, the characterizing at 205 may include determining at least a portion
of an equation of
state for a mixture of the given diluent and the viscous hydrocarbons. As
another example, the
characterizing at 205 may include deteimining a chemical composition of the
viscous
hydrocarbons.
As used herein, the phrase "critical diluent-to-viscous-hydrocarbon ratio" may
refer to a
ratio of the given diluent to viscous hydrocarbons below which the resulting
mixture generates a
21
CA 02898943 2015-07-30
single liquid phase and above which the resulting mixture generates two phase-
separated liquid
phases, at a given temperature and a given pressure. Stated another way, when
the given diluent
and the viscous hydrocarbons are mixed, or combined at a given temperature and
a given
pressure, at a ratio that is less than the critical diluent-to-viscous-
hydrocarbon ratio, the given
diluent and the viscous hydrocarbons combine to generate the single liquid
phase, which includes
diluted viscous hydrocarbons. In contrast, when the given diluent and the
viscous hydrocarbons
are mixed, or combined at a given temperature and a given pressure, at a ratio
that is greater than
the critical diluent-to-viscous-hydrocarbon ratio, the given diluent and the
viscous hydrocarbons
combine to generate two phase-separated liquid phases, including a heavy
liquid hydrocarbon
fraction, which includes a heavy liquid hydrocarbon, and a separate light
liquid hydrocarbon
fraction, which includes a light liquid hydrocarbon. It is within the scope of
the present
disclosure that the critical diluent-to-viscous-hydrocarbon ratio may include
and/or be any
suitable measure, or ratio, of an amount, mass, or volume of the given diluent
to an amount,
mass, or volume of viscous hydrocarbons with which the diluent is combined.
Selecting the diluent property at 210 may include selecting any suitable
property. As
examples, the selecting at 210 may include selecting a chemical composition of
the diluent,
selecting a temperature of the diluent, selecting a temperature of the diluent
to be utilized during
the injecting at 225, selecting a pressure of the diluent, selecting a
pressure of the diluent to be
utilized during the injecting at 225, selecting a volume of the diluent,
selecting a volume of the
diluent to be utilized during the injecting at 225, and/or selecting a
predeteimined volume of the
diluent to be utilized during the injecting at 225. These diluent properties
may specify and/or
define the given diluent that is utilized during the characterizing at 205
and/or the diluent that is
injected during the injecting at 225.
22
CA 02898943 2015-07-30
=
As another example, the selecting at 210 may include selecting such that a
portion of the
product hydrocarbon stream, which is produced during the producing at 240,
that comprises
diluted viscous hydrocarbons is expected to be greater than a threshold
portion of the product
hydrocarbon stream. As yet another example, the selecting at 210 may include
selecting the
predetermined volume of the diluent to maintain the diluent-to-viscous-
hydrocarbon ratio within
the subterranean formation below the critical diluent-to-viscous-hydrocarbon
ratio.
The selecting at 210 may be based upon any suitable criteria. As examples, the
selecting
at 210 may be based, at least in part, on the critical diluent-to-viscous-
hydrocarbon ratio, on the
characterizing at 205, and/or on the composition of the viscous hydrocarbons.
The selecting at 210 may be perfoimed with any suitable sequence and/or timing
within
methods 200. As examples, the selecting at 210 may be performed subsequent to
the
characterizing at 205 and/or prior to the injecting at 225.
Calculating the quantity of heat at 215 may include calculating the quantity
of heat that is
required to heat a portion of the subterranean formation to at least a
threshold upper temperature
and/or to within a target temperature range. The calculating at 215 may be
performed in any
suitable manner and/or based upon any suitable criteria. As examples, the
calculating at 215, the
threshold upper temperature, and/or the target temperature range may be
selected based, at least
in part, on the characterizing at 205, on a volume of the portion of the
subterranean formation, on
a composition of subterranean strata that is present within the portion of the
subterranean
formation, and/or on a model of the portion of the subterranean formation.
Heating the subterranean folination at 220 may include heating at least the
portion of the
subterranean foiniation. The heating at 220 may include providing the quantity
of heat, which
was calculated during the calculating at 215, to the subterranean formation
and/or heating the
23
CA 02898943 2015-07-30
subterranean formation to the given temperature that was utilized during the
characterizing at
205. Additionally or alternatively, the heating at 220 may include selecting
the given
temperature based, at least in part, on the characterizing at 205.
The heating at 220 may be accomplished in any suitable manner, including those
that are
conventional to hydrocarbon production and/or stimulation techniques and/or
processes. As
examples, the heating at 220 may include providing steam or heated flue gas to
the portion of the
subterranean formation, heating the diluent prior to the injecting at 225,
and/or combusting a
fuel, such as diluent or methane, within the portion of the subterranean
formation. When steam
is injected into the subterranean formation to provide at least a portion of
the desired heating, the
steam may be injected at any suitable time relative to the injection of the
diluent. Examples
include prior to the injection of the diluent, prior to injection of the
modified diluent, concurrent
with the injection of the diluent, and/or concurrent with the injection of the
modified diluent.
When methods 200 include the heating at 220, the methods further may include
monitoring a temperature, such as a temperature associated with the
hydrocarbon well, a
temperature of the portion of the subterranean formation, and/or a temperature
of the product
hydrocarbon stream. Under these conditions, the methods further may include
repeating the
heating at 220 responsive to the temperature being less than a threshold lower
temperature.
Injecting the diluent into the subterranean formation at 225 may include
injecting any
suitable diluent into the subterranean foimation. As an example, the injecting
at 225 may
include injecting the given diluent that is utilized during the characterizing
at 205 and/or
injecting the diluent that is specified and/or defined by the selecting at
210. The diluent may, or
the injecting at 225 may be performed to, dilute the viscous hydrocarbons
and/or to generate
reduced-viscosity hydrocarbons within the subterranean formation. The reduced-
viscosity
24
CA 02898943 2015-07-30
hydrocarbons may include a diluted viscous hydrocarbon fraction (i.e., a
portion, percentage,
and/or subset of the reduced-viscosity hydrocarbons may be defined by diluted
viscous
hydrocarbons).
The injecting at 225 may be performed in any suitable manner. As examples, the
injecting at 225 may include injecting via a wellbore that extends within the
subterranean
formation, injecting from a surface region into the subterranean formation,
and/or pumping the
diluent into the subterranean formation.
In addition, the injecting at 225 may be performed at any suitable time and/or
with any
suitable sequence during methods 200. As examples, the injecting at 225 may be
performed
subsequent to the characterizing at 205, subsequent to the selecting at 210,
subsequent to the
calculating at 215, subsequent to the heating at 220, concurrently with the
heating at 220, prior to
the ceasing at 230, prior to the regulating at 235, and/or prior to the
producing at 240.
Ceasing the injecting at 230 may include ceasing injection of the diluent into
the
subterranean formation and/or ceasing the injecting at 225. The ceasing at 230
may include
limiting, restricting, occluding, blocking, and/or stopping flow of the
diluent into the
subterranean formation and/or stopping supply of the diluent to the wellbore.
When methods
200 include the ceasing at 230, methods 200 further may include waiting at
least a threshold soak
time subsequent to the ceasing at 230 and prior to the producing at 240. The
waiting may permit
the diluent to diffuse within the subterranean formation and/or to be absorbed
into the viscous
hydrocarbons, thereby producing the reduced-viscosity hydrocarbons. Examples
of threshold
soak times include at least 15 days, at least 30 days, at least 60 days, at
least 90 days, and at least
120 days, although threshold soak times may be selected and utilized, such as
based on
conditions relating to a particular formation, operator preferences, etc.
CA 02898943 2015-07-30
Regulating the pressure at 235 may include regulating the pressure within the
subterranean foimation, such as during the threshold soak time or during
production at 240. The
regulating at 235 may be accomplished in any suitable manner. As examples, the
regulating at
235 may include monitoring the pressure within the subterranean formation,
providing a
pressurizing fluid to the subterranean formation responsive to the pressure
within the
subterranean formation being less than a threshold lower formation pressure,
and/or releasing
fluid from the subterranean foiniation responsive to the pressure within the
subterranean
formation being greater than a threshold upper formation pressure.
Producing the product hydrocarbon stream from the subterranean formation at
240 may
include removing any suitable product hydrocarbon stream from the subterranean
formation in
any suitable manner. As an example, the producing at 240 may include flowing
the product
hydrocarbon stream from the subterranean formation, such as via the wellbore.
As another
example, the producing at 240 may include permitting the product hydrocarbon
stream to flow
from the subterranean formation, with a motive force for the flow of the
product hydrocarbon
stream being provided by a pressure that was generated within the subterranean
formation during
the injecting at 225. As yet another example, the producing at 240 may include
pumping the
product hydrocarbon stream from the subterranean foimation.
As discussed in more detail herein, the product hydrocarbon stream generally
will include
at least a portion of the reduced-viscosity hydrocarbons that were generated
as a result of the
injecting at 225. Additionally or alternatively, the product hydrocarbon
stream also may include
diluted viscous hydrocarbons, the light liquid hydrocarbon, and/or the heavy
liquid hydrocarbon.
Ceasing the producing at 245 may include ceasing production of the product
hydrocarbon
stream from the subterranean foi illation and may be accomplished in any
suitable manner. As
26
CA 02898943 2015-07-30
examples, the ceasing at 245 may include blocking flow of the product
hydrocarbon stream from
the subterranean founation and/or ceasing pumping of the product hydrocarbon
stream from the
subterranean formation.
The ceasing at 245 may be initiated, or the producing at 240 may be stopped,
based upon
any suitable criteria. As examples, the ceasing at 245 may be initiated
responsive to a
temperature of the product hydrocarbon stream being less than a lower stream
temperature
threshold, responsive to a temperature of the portion of the subterranean
formation being less
than a lower formation temperature threshold, responsive to a pressure of the
product
hydrocarbon stream being less than a lower stream pressure threshold,
responsive to a pressure
within the portion of the subterranean formation being less than a lower
formation pressure
threshold, and/or responsive to a product hydrocarbon stream rate being less
than a lower
product hydrocarbon stream rate.
Monitoring the variable of the product hydrocarbon stream at 250 may include
monitoring any suitable variable that may be indicative of the diluted viscous
hydrocarbon
fraction of the reduced-viscosity hydrocarbons that are produced in the
product hydrocarbon
stream. As an example, the monitoring at 250 may include monitoring a chemical
composition
of the diluted viscous hydrocarbon fraction of the product hydrocarbon stream.
As another
example, the monitoring at 250 may include monitoring a chemical composition
of the light
liquid hydrocarbon fraction of the product hydrocarbon stream. As yet another
example, the
monitoring at 250 may include monitoring a chemical composition of the heavy
liquid
hydrocarbon fraction of the product hydrocarbon stream. As another example,
the monitoring at
250 may include determining a portion, fraction, subset, and/or percentage of
the product
hydrocarbon stream that includes, or comprises, the diluted viscous
hydrocarbon fraction (e.g.,
27
CA 02898943 2015-07-30
determining what weight percentage, mass percentage, and/or mole percentage of
the product
hydrocarbon stream is defined by diluted viscous hydrocarbons).
As yet another example, the monitoring at 250 may include determining a
portion,
fraction, subset, and/or percentage of the product hydrocarbon stream that
includes, or
comprises, the light liquid hydrocarbon fraction (e.g., determining what
weight percentage, mass
percentage, and/or mole percentage of the product hydrocarbon stream is
defined by the light
liquid hydrocarbon). As yet another example, the monitoring at 250 may include
deteimining a
portion, fraction, subset, and/or percentage of the product hydrocarbon stream
that includes, or
comprises, the heavy liquid hydrocarbon fraction (e.g., deteimining what
weight percentage,
mass percentage, and/or mole percentage of the product hydrocarbon stream is
defined by the
heavy liquid hydrocarbon. As additional examples, the monitoring at 250 may
include
monitoring a temperature of the product hydrocarbon stream, monitoring a
viscosity of the
product hydrocarbon stream, monitoring a density of the product hydrocarbon
stream,
monitoring a color of the product hydrocarbon stream, and/or monitoring a
diluent-to-viscous-
hydrocarbon ratio of, or in, the product hydrocarbon stream. As yet another
example, the
monitoring at 250 may include monitoring the amount of and/or composition of
non-condensable
gas, such as N2, CH4, or CO2, in the product hydrocarbon stream.
It is within the scope of the present disclosure that the monitoring at 250
may include
monitoring an instantaneous value of the variable and/or monitoring a
cumulative, or integrated,
value of the variable.
Adjusting the at least one property of the diluent to define the modified
diluent at 255
may include adjusting such that the modified diluent differs from the diluent
that was injected
during the injecting at 225 by the at least one property. Additionally or
alternatively, the
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CA 02898943 2015-07-30
adjusting at 255 also may include adjusting to mitigate, regulate, control,
and/or decrease
formation of the heavy liquid hydrocarbon fraction within the subterranean
formation. The
adjusting at 255 may be based, at least in part, on the variable of the
product hydrocarbon stream
that was monitored during the monitoring at 250.
The at least one property of the diluent may include and/or be any suitable
property of the
diluent. As examples, the at least one property of the diluent may include
and/or be a volume of
the modified diluent relative to a volume of the diluent (e.g., a volume of
the modified diluent
that may be injected into the subterranean formation, such as during the
repeating at 260, relative
to a volume of the diluent that was injected during the injecting at 225), a
chemical composition
of the modified diluent relative to a chemical composition of the diluent,
and/or a temperature of
the modified diluent relative to a temperature of the diluent. Thus, the
chemical composition
may be adjusted by adding and/or removing a component of the diluent and/or
increasing or
decreasing the relative proportion of at least one component of the diluent.
Adjusting at 255 may include changing the composition of and/or increasing or
decreasing the concentration of non-condensable gases in the diluent.
Similarly, adjusting a
temperature or pressure may include increasing or decreasing the corresponding
temperature or
pressure.
Responsive to the monitoring at 250 indicating that the diluted viscous
hydrocarbon
fraction of the reduced-viscosity hydrocarbons that are produced in the
product hydrocarbon
stream (i.e., the portion of the product hydrocarbon stream that comprises the
diluted viscous
hydrocarbon fraction) is less than a threshold portion of the product
hydrocarbon stream,
methods 200 further may include increasing a temperature of the subterranean
foimation,
increasing a concentration and/or changing the composition of a non-
condensable gas (such as
29
CA 02898943 2015-07-30
methane or nitrogen or CO2) in the modified diluent relative to a
concentration of the non-
condensable gas in the diluent, increasing a concentration of dimethyl ether
in the modified
diluent relative to a concentration of dimethyl ether within the diluent,
and/or decreasing a
diluent-to-viscous-hydrocarbon ratio of the modified diluent relative to the
diluent. Conversely,
and responsive to the monitoring at 250 indicating that the diluted viscous
hydrocarbon fraction
of the reduced-viscosity hydrocarbons that are produced in the product
hydrocarbon stream (i.e.,
the portion of the product hydrocarbon stream that comprises the diluted
viscous hydrocarbon
fraction) is greater than the threshold portion of the product hydrocarbon
stream, methods 200
further may include decreasing the concentration of the non-condensable gas in
the modified
diluent relative to the concentration of the non-condensable gas in the
diluent, decreasing the
concentration of dimethyl ether in the modified diluent relative to the
concentration of dimethyl
ether within the diluent, and/or increasing the diluent-to-viscous-hydrocarbon
ratio of the
modified diluent relative to the diluent.
Repeating at least the portion of the methods at 260 may include repeating any
suitable
portion of methods 200 in any suitable manner. As an example, the repeating at
260 may include
repeating the characterizing at 205, the selecting at 210, the calculating at
215, the heating at
220, the injecting at 225, the ceasing at 230, the regulating at 235, the
producing at 240, the
ceasing at 245, the monitoring at 250, and/or the adjusting at 255 a plurality
of times as a part of
a plurality of stimulation-production cycles. The repeating at 260 may include
repeating at least
the calculating at 215, the heating at 220, the injecting at 225, the ceasing
at 230, the regulating
at 235, the producing at 240, and the monitoring at 250 a plurality of times
prior to performing
the adjusting at 255.
CA 02898943 2015-07-30
As another example, the product hydrocarbon stream may be a first product
hydrocarbon
stream and the diluted viscous hydrocarbon fraction may be a first diluted
viscous hydrocarbon
fraction. Under these conditions, the repeating at 260 may include repeating
the injecting at 225
to inject and/or supply the modified diluent to the subterranean folination,
to dilute the viscous
hydrocarbons, and/or to generate reduced-viscosity hydrocarbons within the
subterranean
formation. The reduced-viscosity hydrocarbons generated during the repeating
at 260 may
include a second diluted viscous hydrocarbon fraction, which may be different
from the first
diluted viscous hydrocarbon fraction. The repeating at 260 further may include
repeating the
producing at 240 to produce a second product hydrocarbon stream from the
subterranean
formation. The repeating at 260 further may include repeating the monitoring
at 250 to monitor
a variable that is indicative of a portion of the second product hydrocarbon
stream that comprises
the second diluted viscous hydrocarbon fraction. The repeating at 260 also may
include
repeating the adjusting at 255 to define another modified diluent to be
supplied to the
subterranean foimation. The other modified diluent may be defined based, at
least in part, on the
portion of the second product hydrocarbon stream that comprises the second
diluted viscous
hydrocarbon fraction.
When methods 200 include the repeating at 260, the adjusting at 255 may
include
adjusting to increase the portion of the second product hydrocarbon stream
that comprises the
(second) diluted viscous hydrocarbon fraction relative to the portion of the
first hydrocarbon
stream that comprises the (first) diluted viscous hydrocarbon fraction.
Additionally or
alternatively, the adjusting at 255 also may include adjusting to maintain the
portion of the
second product hydrocarbon stream that comprises the (second) diluted viscous
hydrocarbon
fraction above a threshold portion of the second product hydrocarbon stream.
Additionally or
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alternatively, the adjusting at 255 may include adjusting to decrease a
viscosity of the second
product hydrocarbon stream relative to the first product hydrocarbon stream,
to decrease a
portion of the second product hydrocarbon stream that comprises the heavy
liquid hydrocarbon
fraction relative to a portion of the first product hydrocarbon stream that
comprises the heavy
liquid hydrocarbon fraction, and/or to maintain the diluent-to-viscous-
hydrocarbon ratio in the
second product hydrocarbon stream below a threshold, or critical, diluent-to-
viscous-
hydrocarbon ratio.
In the present disclosure, several of the illustrative, non-exclusive examples
have been
discussed and/or presented in the context of flow diagrams, or flow charts, in
which the methods
are shown and described as a series of blocks, or steps. Unless specifically
set forth in the
accompanying description, it is within the scope of the present disclosure
that the order of the
blocks may vary from the illustrated order in the flow diagram, including with
two or more of the
blocks (or steps) occurring in a different order and/or concurrently.
As used herein, the term "and/or" placed between a first entity and a second
entity means
one of (1) the first entity, (2) the second entity, and (3) the first entity
and the second entity.
Multiple entities listed with "and/or" should be construed in the same manner,
i.e., "one or more"
of the entities so conjoined. Other entities may optionally be present other
than the entities
specifically identified by the "and/or" clause, whether related or unrelated
to those entities
specifically identified. Thus, as a non-limiting example, a reference to "A
and/or B," when used
in conjunction with open-ended language such as "comprising" may refer, in one
embodiment, to
A only (optionally including entities other than B); in another embodiment, to
B only (optionally
including entities other than A); in yet another embodiment, to both A and B
(optionally
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including other entities). These entities may refer to elements, actions,
structures, steps,
operations, values, and the like.
As used herein, the phrase "at least one," in reference to a list of one or
more entities
should be understood to mean at least one entity selected from any one or more
of the entity in
the list of entities, but not necessarily including at least one of each and
every entity specifically
listed within the list of entities and not excluding any combinations of
entities in the list of
entities. This definition also allows that entities may optionally be present
other than the entities
specifically identified within the list of entities to which the phrase "at
least one" refers, whether
related or unrelated to those entities specifically identified. Thus, as a non-
limiting example, "at
least one of A and B" (or, equivalently, "at least one of A or B," or,
equivalently "at least one of
A and/or B") may refer, in one embodiment, to at least one, optionally
including more than one,
A, with no B present (and optionally including entities other than B); in
another embodiment, to
at least one, optionally including more than one, B, with no A present (and
optionally including
entities other than A); in yet another embodiment, to at least one, optionally
including more than
one, A, and at least one, optionally including more than one, B (and
optionally including other
entities). In other words, the phrases "at least one," "one or more," and
"and/or" are open-ended
expressions that are both conjunctive and disjunctive in operation. For
example, each of the
expressions "at least one of A, B and C," -at least one of A, B, or C," "one
or more of A, B, and
C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B
alone, C alone, A
and B together, A and C together, B and C together, A, B and C together, and
optionally any of
the above in combination with at least one other entity.
In the event that any patents, patent applications, or other references are
incorporated by
reference herein and (1) define a term in a manner that is inconsistent with
and/or (2) are
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otherwise inconsistent with, either the non-incorporated portion of the
present disclosure or any
of the other incorporated references, the non-incorporated portion of the
present disclosure shall
control, and the teim or incorporated disclosure therein shall only control
with respect to the
reference in which the term is defined and/or the incorporated disclosure was
present originally.
As used herein the terms "adapted" and "configured" mean that the element,
component,
or other subject matter is designed and/or intended to perform a given
function. Thus, the use of
the terms "adapted" and "configured" should not be construed to mean that a
given element,
component, or other subject matter is simply "capable of' performing a given
function but that
the element, component, and/or other subject matter is specifically selected,
created,
implemented, utilized, programmed, and/or designed for the purpose of
performing the function.
It is also within the scope of the present disclosure that elements,
components, and/or other
recited subject matter that is recited as being adapted to perform a
particular function may
additionally or alternatively be described as being configured to perform that
function, and vice
versa.
As used herein, the phrase, "for example," the phrase, "as an example," and/or
simply the
telin "example," when used with reference to one or more components, features,
details,
structures, embodiments, and/or methods according to the present disclosure,
are intended to
convey that the described component, feature, detail, structure, embodiment,
and/or method is an
illustrative, non-exclusive example of components, features, details,
structures, embodiments,
and/or methods according to the present disclosure. Thus, the described
component, feature,
detail, structure, embodiment, and/or method is not intended to be limiting,
required, or
exclusive/exhaustive; and other components, features, details, structures,
embodiments, and/or
methods, including structurally and/or functionally similar and/or equivalent
components,
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features, details, structures, embodiments, and/or methods, are also within
the scope of the
present disclosure.
Industrial Applicability
The methods disclosed herein are applicable to the oil and gas industries.
It is believed that the disclosure set forth above encompasses multiple
distinct inventions
with independent utility. While each of these inventions has been disclosed in
its preferred form,
the specific embodiments thereof as disclosed and illustrated herein are not
to be considered in a
limiting sense as numerous variations are possible. The subject matter of the
inventions includes
all novel and non-obvious combinations and subcombinations of the various
elements, features,
functions and/or properties disclosed herein. Similarly, where the claims
recite "a" or "a first"
element or the equivalent thereof, such claims should be understood to include
incorporation of
one or more such elements, neither requiring nor excluding two or more such
elements.
It is believed that the following claims particularly point out certain
combinations and
subcombinations that are directed to one of the disclosed inventions and are
novel and non-
obvious. Inventions embodied in other combinations and subcombinations of
features, functions,
elements and/or properties may be claimed through amendment of the present
claims or
presentation of new claims in this or a related application. Such amended or
new claims,
whether they are directed to a different invention or directed to the same
invention, whether
different, broader, narrower, or equal in scope to the original claims, are
also regarded as
included within the subject matter of the inventions of the present
disclosure.
