Note: Descriptions are shown in the official language in which they were submitted.
PAT 104239-1
PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN
HYDROCARBON-BEARING FORMATION
TECHNICAL FIELD
[0001] The present disclosure relates to the production of hydrocarbons
from a subterranean formation bearing heavy oil or bitumen.
BACKGROUND DISCUSSION
[0002] Extensive deposits of viscous hydrocarbons exist around the world.
Reservoirs of such deposits may be referred to as reservoirs of heavy
hydrocarbon, heavy oil, extra-heavy oil, bitumen, or oil sands, and include
large
subterranean deposits in Alberta, Canada that are not susceptible to standard
oil
well production technologies. The hydrocarbons in such deposits are typically
highly viscous and do not flow at commercially relevant rates at the
temperatures and pressures present in the reservoir. For such reservoirs,
various
recovery techniques may be utilized to mobilize the hydrocarbons and produce
the mobilized hydrocarbons from wells drilled in the reservoirs. For example,
thermal techniques may be used to heat the reservoir to mobilize the
hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
[0003] Hydrocarbon substances of high viscosity are generally categorized
as "heavy oil" or as "bitumen". 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 such types of oil herein include the continuum of such
substances,
and do not imply the existence of some fixed and universally recognized
boundary between the substances.
[0004] One thermal method of recovering viscous hydrocarbons from a
subterranean hydrocarbon-bearing formation using spaced horizontal wells is
known as steam-assisted gravity drainage (SAGD). Various embodiments of the
SAGD process are described in Canadian Patent No. 1,304,287 and
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corresponding U.S. Patent No. 4,344,485. In the SAGD process, steam is
injected through an upper, horizontal, injection well into a viscous
hydrocarbon
reservoir while hydrocarbons are produced from a lower, parallel, horizontal,
production well that is vertically spaced from and near the injection well.
The
injection and production wells are located close to the base of the
hydrocarbon
deposit to collect the hydrocarbons that flow toward the production well.
[0005] Such thermal processes are extremely energy intensive, utilize
significant volumes of water for the production of steam, and may require
additional equipment to handle the steam or gasses produced.
[0006] A solvent may be used to aid a steam-assisted recovery process, in
a so-called solvent-aided process (SAP). Hydrocarbon solvent is generally used
to improve mobility in the hydrocarbon reservoir, potentially improving
production and/or reducing steam and/or heating requirements. However, the
use of solvent can add significant expense due to solvent costs; and, if
injected
solvent is to be recovered and/or recycled, additional surface processing
apparatus may be needed.
[0007] Commercial applications of solvent-aided recovery processes have
been limited to date. Challenges remain in providing solvent-aided recovery
processes for efficient and effective commercial application.
SUMMARY
[0008] In an aspect of the present disclosure, there is provided a
process
for producing hydrocarbons from a subterranean hydrocarbon-bearing formation
that includes, during a production phase after a start-up phase, injecting a
first
fluid into a reservoir of the formation through an injection well to form a
chamber and producing at least a portion of the hydrocarbons to a surface
through a production well; while producing the at least a portion of the
hydrocarbons to the surface, iteratively, injecting a second fluid into the
reservoir through the injection well at a first rate to adjust a pressure in
the
reservoir to a first pressure value, and after the first pressure value is
reached,
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injecting a third fluid into the reservoir through the injection well at a
second
rate to adjust the pressure in the reservoir to a second pressure value, such
that
a difference between the first pressure value and the second pressure value is
at
least about 25% of the higher of the first and second pressure values.
[0009] The first fluid may be injected into the reservoir through the
injection well until the chamber contacts a formation ceiling of the
reservoir, and
the second fluid may be injected into the reservoir at the first rate to
adjust the
pressure in the reservoir after the chamber reaches the formation ceiling.
[0010] The first fluid may be steam that does not contain a significant
amount of solvent.
[0011] The second fluid may include a first mixture of steam and a first
viscosity reducing solvent and the third fluid may include a second mixture of
steam and a second viscosity reducing solvent.
[0012] The first viscosity reducing solvent of the first mixture may
comprise one or more alkanes having 2 to 9 carbon atoms and the second
viscosity reducing solvent of the second mixture may comprise one or more
alkanes having 2 to 9 carbon atoms.
[0013] The first viscosity reducing solvent may be one or more of natural
gas condensate, liquefied petroleum, hexane, pentane, butane, propane, and
ethane, and the second viscosity reducing solvent may be one or more of
natural
gas condensate, liquefied petroleum, hexane, pentane, butane, propane, and
ethane.
[0014] The first viscosity reducing solvent may be the same as the second
viscosity reducing solvent.
[0015] A first amount of the first solvent in the first mixture may be
between about greater than 20 percent by weight (wt%) of the first mixture and
about 80 wt% of the first mixture, and a second amount of the second solvent
in
the second mixture may be between greater than about 20 wt% and about 80
wt% of the second mixture.
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[0016] A first amount of the first solvent in the first mixture may be
between about 40 percent by weight (wt%) of the first mixture and about 80
wt% of the first mixture, and a second amount of the second solvent in the
second mixture may be between about 40 wt% and about 80 wt% of the second
mixture.
[0017] A first amount of the first solvent in the first mixture may be
about
50 wt% of the first mixture, and a second amount of the second solvent in the
second mixture may be about 50 wt% of the second mixture.
[0018] The first amount may be the same as the second amount.
[0019] The first viscosity reducing solvent may be the same as the second
viscosity reducing solvent.
[0020] The second fluid may include a third mixture of steam and a third
viscosity reducing solvent, and a third amount of the third viscosity reducing
solvent in the third mixture may be between about 5 percent by weight (wt%)
and about 20 wt% of the third mixture.
[0021] The first pressure value may be higher than the second pressure
value, and the third fluid may be steam that does not contain a significant
amount of a solvent.
[0022] The third fluid may include a fourth mixture of steam and a fourth
viscosity reducing solvent, and a fourth amount of the fourth viscosity
reducing
solvent in the fourth mixture may be between about 5 wt% and about 20 wt% of
the fourth mixture.
[0023] The third amount may be the same as the fourth amount.
[0024] The third viscosity reducing solvent may be the same as the fourth
viscosity reducing solvent.
[0025] The third viscosity reducing solvent may comprise one or more
alkanes having 2 to 9 carbon atoms and the fourth viscosity reducing solvent
may comprise one or more alkanes having 2 to 9 carbon atoms.
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[0026] The difference between the first pressure value and the second
pressure value may be less than or equal to about 75% of the higher of the
first
and second pressure values.
[0027] The difference may be between about 50% and about 75% of the
higher of the first and second pressure values.
[0028] The first pressure value may be greater than the second pressure
value by an amount in a range of about 1000 kPa to about 3000 kPa.
[0029] The greater of the first pressure value and the second pressure
value may be less than the maximum operating pressure of the reservoir.
[0030] The first pressure value may be maintained for a time duration
before injecting the third fluid at the second rate, and the second pressure
value
may be maintained in the reservoir for the time duration before injecting the
second fluid at the first rate.
[0031] The time duration may be at least about 5 days.
[0032] The time duration may be about 15 days.
[0033] The time duration may be about 30 days.
[0034] The time duration may increase in length over time, such that the
time duration during a subsequent iteration is longer than the time duration
of a
previous iteration.
BRIEF DESCRIPTION OF THE DRAWINGS
[0035] Embodiments of the present application will now be described, by
way
of example only, with reference to the attached Figures, wherein:
[0036] FIG. 1 is a sectional view through a reservoir, illustrating a
well
pair;
[0037] FIG. 2 is a series of cross sectional views illustrating a well
pair
including an injection well and a production well during various stages of a
hydrocarbon recovery process;
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[0038] FIG. 3 is a graph illustrating data of the measured oil production
rate at a production well and the measured pressure in the injection well as a
function of time during a solvent-aided process;
[0039] FIG. 4 is a graph illustrating data of the measured oil production
rate
at a production well and the measured pressure in the injection well as a
function
of time during another solvent-aided process;
[0040] FIG. 5 is a graph showing cumulative steam oil ratios (CSOR) as a
function of time for three simulations of hydrocarbon recovery processes;
[0041] FIG. 6 is a graph showing oil production rates as a function of
time
for the three simulations of hydrocarbon recovery processes shown in FIG. 5;
[0042] FIG. 7 is a graph showing cumulative oil production as a function
of
time for the three simulations of hydrocarbon recovery processes shown in FIG.
5
and FIG. 6;
[0043] FIG. 8 is a graph showing cumulative solvent injected as a
function
of time for two of the three simulations shown in FIG. 5 though FIG. 7;
[0044] FIG. 9 is a graph showing cumulative oil production rates as a
function
of time for five simulations of various hydrocarbon recovery processes
utilizing
solvents with and without pressure cycling; and
[0045] FIG. 10 is a flow chart illustrating a process for recovering
hydrocarbons from a subterranean formation according to an embodiment of the
present disclosure.
DETAILED DESCRIPTION
[0046] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described herein. The examples may be practiced without these details. In
other instances, well-known methods, procedures, and components are not
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described in detail to avoid obscuring the examples described. The description
is
not to be considered as limited to the scope of the examples described herein.
[0047] The present disclosure generally relates to a process for
recovering
hydrocarbons from a hydrocarbon-bearing formation. The process includes,
during a production phase after a start-up phase, injecting a first fluid into
a
reservoir of the formation through an injection well to form a vapor chamber
and
producing at least a portion of the hydrocarbons to a surface through a
production well; while producing the at least a portion of the hydrocarbons to
the
surface, iteratively, injecting a second fluid into the reservoir through the
injection well at a first rate to adjust a pressure in the reservoir to a
first
pressure value, and after the first pressure value is reached, injecting a
third
fluid into the reservoir through the injection well at a second rate to adjust
the
pressure in the reservoir to a second pressure value, such that a difference
between the first pressure value and the second pressure value is at least
about
25% of the higher of the first and second pressure values.
[0048] A steam-assisted gravity drainage (SAGD) process may be utilized
for mobilizing viscous hydrocarbons. In the SAGD process, a well pair,
including
a hydrocarbon production well (producer) and a steam injection well (injector)
are utilized. One example of a hydrocarbon production well 100 and injection
well 108 is illustrated in FIG. 1. The hydrocarbon production well 100
includes a
generally horizontal segment 102 that extends near the base or bottom 104 of
the hydrocarbon reservoir 106. The injection well 108 also includes a
generally
horizontal segment 110 that is disposed generally parallel to and is spaced
generally vertically above the horizontal segment 102 of the hydrocarbon
production well 100.
[0049] During SAGD, steam is injected into the injection well 108 to
mobilize the hydrocarbons and create a chamber (called a steam chamber)
(shown in FIG. 2) in the reservoir 106, around and above the generally
horizontal segment 110.
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[0050] 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, the steam chamber is the
region of the reservoir in fluid communication with the steam injection well,
which is also the region that is subject to depletion, primarily by gravity
drainage, into the production well. In a SAP, the chamber may be referred to
as
a vapor chamber.
[0051] In general, a SAGD process may be described as including three
stages: the start-up stage; the production stage; and the wind-down (or
blowdown) stage. The production stage may be described as including further
stages such as, for example, a ramp-up stage and a plateau stage.
[0052] FIG. 2 shows examples of cross sectional views of the horizontal
segments 102, 110 of the production well 100 and the injection well 108,
respectively. In FIG. 2, (a) shows an example start-up stage, (b) shows an
example ramp-up stage of a production stage, and (c) shows an example plateau
stage of the production stage.
[0053] Generally, during the start-up stage, heat is transferred to the
hydrocarbons within the near-wellbore region 206 of the reservoir near the
horizontal sections 110 and 102 of the injection well 108 and production well
100, respectively. The hydrocarbons are heated to increase mobility of the
hydrocarbons in order to establish fluid communication between the injection
well 108 and the production well 100. Once fluid communication is established,
the start-up stage ends and the production stage begins. The start-up stage
may be performed by any suitable method.
[0054] FIG. 2 shows one example of a start-up stage at (a) in which heat
from each of the production well horizontal segment 102 and the injection well
horizontal segment 110 is transferred to the hydrocarbons in the near-wellbore
region 206. The hydrocarbons within the regions 202 and 204 have been heated
by heat from the production well horizontal segment 102 and the injection well
horizontal segment 110, respectively. As further heat is transferred to the
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hydrocarbons in the near-wellbore region 206, the regions 202 and 204 grow
until they eventually merge, establishing fluid communication between the
horizontal sections 102, 110 of the production well 100 and the injection well
108, respectively.
[0055] The horizontal section 110 of the injection well 108 and the
horizontal segment 102 of the production well 100 may be heated to transfer
heat to the reservoir in any suitable manner including, for example,
circulating a
heated fluid through the horizontal segments 102, 110 such that the fluid is
not
injected into the reservoir to any significant degree. In other examples,
heaters
may be placed in the injection well horizontal segment 110 and the production
well horizontal segment 102, or a heated fluid may be injected into the
reservoir
through openings in the horizontal segments 102, 110. The heated fluid may be,
for example, steam or a mixture of steam and one or more solvents.
[0056] During the ramp-up stage, steam is injected into the reservoir
through the horizontal segment 110 of the injection well 108. Heated fluid
that
is circulated through the producer well 100 or injected into the reservoir
through
the horizontal segment 102 of the producer well 100 during the start-up stage
is
discontinued. If needed after start-up, the producer well segment 102 may be
re-completed to produce the mobile hydrocarbons to the surface. During the
production stage in a conventional SAGD operation, steam is injected through
the injector well horizontal segment 110 at a substantially constant pressure,
i.e., fluctuations in the pressure in a conventional SAGD operation may be
less
than or equal to about 12.5% higher or lower than the operating pressure. As
shown in (b) of FIG. 2, the injected steam forms a vapor chamber 208 having an
edge 210, which is the boundary between the heated steam and the
hydrocarbons which are at a lower temperature, such as an initial reservoir
temperature.
[0057] In some typical bitumen reservoirs found in Alberta, Canada, the
natural or initial temperature in the reservoir prior to hydrocarbon recovery
may
be between about 7 C and about 12 C, and the natural or initial pressure in
the
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reservoir may be between about 1 MPa and about 5 MPa. In different reservoirs,
the initial temperature and pressure may be different.
[0058] As steam is injected, a vapor chamber 208 expands upwardly, and
laterally to some degree, until the edge 210 contacts the overlying formation
ceiling 212, as shown in (c) of FIG. 2, after which the vapor chamber
continues
to expand laterally. Typically, the rate of production of hydrocarbons at the
production well 100 does not increase after the edge 210 of the vapor chamber
208 contacts the formation ceiling 212, but will remain constant for the next
two
to three years, for example. Because the rate of production does not typically
increase after the vapor chamber 208 reaches the formation ceiling 212 as
shown in (c) of FIG. 2, this stage of production is referred as the plateau
stage.
[0059] Steam that is injected through the injection well 108 moves
outwards, towards the edge 210 of the vapor chamber 208, where the steam
comes into contact with the hydrocarbons which are at a lower temperature,
such as an initial reservoir temperature, in what is referred to as the
"mixing
zone" 214. Energy is transferred from the steam to the hydrocarbons at the
edge 210 of the vapor chamber 208, heating the hydrocarbons in the mixing
zone 214, which reduces the viscosity and increases the mobility of the heated
hydrocarbons. The mobile hydrocarbons heated at the edge 210 of the vapor
chamber 208 flow due to gravity toward the producer well 100 in side drained
flow, illustrated by the arrows shown in the mixing zone 214 of the vapor
chamber 208 shown in (c) of FIG. 2.
[0060] Depending on the spacing between a pair of production and
injection wells (not shown) adjacent the well pair of the production well 100
and
the injection well 108 shown in FIG. 2, the vapor chamber (not shown) of the
adjacent well pair will eventually coalesce with the vapor chamber 208 such
that
further significant growth of the vapor chamber 208 is not feasible. The stage
after this coalescence of adjacent vapor chambers occurs may be referred to as
the wind-down (or blowdown) stage. At this stage, the production stage is
ended. During the wind-down stage, further steam injection is generally
terminated or curtailed and a non-condensable gas (NCG) gas may be injected
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into the reservoir through the injection well segment 108 to maintain the
pressure in the reservoir. In the wind-down stage the oil production declines
until the wells are eventually abandoned.
[0061] Light hydrocarbons, such as butane and propane, may optionally be
injected into the injection well 108 during the production stage, in addition
to the
steam. The injected light hydrocarbons function as solvents in aiding the
mobilization of the hydrocarbons. The co-injection of light hydrocarbons with
steam may be part of a process referred to as a solvent-aided process (SAP).
SAPs include steam driven solvent processes in which the amount of steam
added is greater than the amount of solvent added, and solvent driven
processes
in which the amount of steam added is less than the amount of solvent added.
In the present disclosure, unless otherwise stated, the term steam driven
solvent
process refers to SAPs in which the amount of solvent injected with the steam
is
between about 1 wt% and about 20 wt% of the mixture of steam and solvent,
and the term hybrid solvent process refers to SAPs in which the amount of
solvent injected with the steam is between about >20 wt% and about 80 wt% of
the mixture.
[0062] Generally, a steam driven solvent process according to the present
disclosure may be initiated at any point during the production stage, whereas
a
hybrid solvent process is generally performed only when the plateau stage of
production is reached, i.e., when the edge 210 of the vapor chamber 208
contacts the ceiling formation of the reservoir.
[0063] Further, a steam driven solvent process may be performed in
reservoirs in which solvent is already present due to injection of solvents
during
the production stage prior to initiating the steam driven solvent process, or
during the start-up stage, or both. By contrast, a hybrid solvent process is
desirably performed only when no, or very little, solvent is present in the
reservoir due to injection during the start-up stage, during the production
stage,
or both, prior to initiating the hybrid solvent process.
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[0064] The present disclosure describes a process that includes
iteratively,
or cyclically, increasing and decreasing (or decreasing and increasing) the
pressure in the reservoir during a production stage of a SAP, such as a steam
driven solvent process or a hybrid solvent process. Cyclically adjusting the
pressure during production may be performed as part of a steam driven solvent
process at any time during the production stage, or may be performed as part
of
a hybrid solvent process during the plateau stage. Cyclically increasing and
decreasing (or decreasing and increasing) the pressure in the reservoir is
performed by increasing and decreasing (or decreasing and increasing) a rate
of
injection of steam, or a mixture of steam and solvent through the injection
well
108. It has been observed that increasing and decreasing the pressure within
the reservoir correlates to an increased rate of production of hydrocarbons at
the
production well 100.
[0065] Without wishing to be bound to a particular theory, the solubility
of
a solvent in hydrocarbons within the reservoir increases with increased
reservoir
pressure.
[0066] Because the thermal diffusivity in oil sands reservoirs is about 3
to 4
orders of magnitude lower than the hydraulic diffusivity, the temperature at
the
edge 210 of the vapor chamber 208 changes at a significantly lower rate than
the pressure diffusion, via Darcy flow, of the vaporized steam and solvents.
This
means that solvents within the vapor chamber 208 diffuse toward the edge 210
at a rate that is faster than the rate of heating of the hydrocarbons at the
edge
210.
[0067] The solvent-hydrocarbon mixture viscosity at the edge 210 is
highly
dependent on solvent solubility. At SAP operating conditions, the solubility
of the
solvent increases with increased pressure and increases with decreased
temperature. Injecting steam or a mixture of steam and solvent at higher
pressures on a consistent basis will eventually cause the temperature at the
edge
210 of the vapor chamber 208 to increase, which negatively affects the solvent
solubility.
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[0068] By cyclically increasing and decreasing the pressure in the
reservoir,
the pressure in the mixing zone 214 may be relatively high during the high
pressure period to increase the solubility of the solvents, but is lowered to
the
low pressure value such that the high pressure condition is not continuously
maintained for such a long period of time that the temperature in the mixing
zone 214 is significantly increased compared to the case in which the
reservoir is
constantly at a high pressure.
[0069] The combination of the lower temperature and higher pressure due
to cyclically increasing and decreasing the pressure of the reservoir results
in
higher solubility, which in turn results in lower viscosity of the solvent-
hydrocarbon mixture and higher fluid drainage rates in the mixing zone 214.
[0070] Further, increased pressure in the reservoir may lead to increased
shear dilation of the oil sands within the reservoir. Shear dilation lowers
the
tortuosity and raises the porosity of the oil sands which lead to enhancement
of
the permeability of fluids, including steam and solvents, through the
reservoir.
By intentionally increasing the pressure within the reservoir, shear dilation
occurs
earlier, and by a greater degree, than during conventional SAGD processes in
which the reservoir pressure may increase more gradually due to normal
changes in operating pressure. Shear dilation effects will be greater in
reservoirs
with a larger ratio of horizontal to vertical principal stresses.
Pressure Cycling in a Steam Driven Solvent Process
[0071] Pressure cycling may be utilized in a steam driven solvent process
in
which the amount of solvent injected with the steam may be less than 50
percent by weight (wt%) of the mixture. In an example, the amount of solvent
injected with steam during pressure cycling in a pressure cycling steam driven
solvent process may be between about 1 wt% of the mixture and about 20 wt%
of the mixture, and desirably the amount of solvent is at least about 5 wt%.
[0072] A pressure cycling steam driven solvent process may be performed
at any time during the production stage of the SAP. In an example, a pressure
cycling steam driven solvent process may be initiated during the plateau stage
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described above, after the vapor chamber has reached the formation ceiling of
the reservoir. A pressure cycling steam driven solvent process may be
performed irrespective of whether solvents are present in the reservoir due to
injection of solvent during the production stage prior to initiating a
pressure
cycling steam driven solvent process, during the start-up stage, or both.
[0073] In a pressure cycling steam driven solvent process a heated fluid
is
injected into the reservoir through a horizontal segment of an injection well
while
hydrocarbons are produced through a horizontal segment of the producer well.
The injection well and the production well may be similar to the injection
well
108 and the production well 100, respectively, described previously with
reference to FIG. 1.
[0074] The rate of injection of the heated fluid may be increased to
cause
the pressure in the reservoir to increase to a desired high pressure value.
Once
a desired high pressure value is reached, the rate of injection of the heated
fluid
may be reduced to lower the reservoir pressure to desired low pressure value.
Once a desired low pressure is reached, the rate of injection may be increased
again in order to iteratively cycle between high and low pressures.
[0075] Alternatively, during the initial cycle, the rate of injection of
the
heated fluid may be reduced to cause the pressure in the reservoir to first be
lowered to a desired low pressure value, then the rate may be increased to
increase the reservoir pressure to a desired high pressure value.
[0076] The heated fluid injected during a pressure cycling steam driven
solvent process may be a mixture of steam and one or more solvents. The
solvents utilized for a pressure cycling steam driven solvent process may be
selected from alkanes having 2 to 9 carbon atoms. The solvent utilized may be
one alkane or a combination of alkanes. A mixture of different solvents may be
utilized in a pressure cycling steam driven solvent process when, for example,
utilizing a single solvent may not be feasible depending on solvent supply.
Examples of solvents that may be utilized in pressure cycling steam driven
solvent processes include natural gas condensate, liquefied petroleum (also
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known as liquefied petroleum gas), hexane, pentane, propane, butane, and
ethane.
[0077] In addition, non-condensing gases such as, for example, methane,
carbon dioxide, nitrogen, or air, or a combination thereof, may be included in
the
heated fluid injected into the reservoir through the injection well.
[0078] In general, the same fluid composition is injected for both
increasing and decreasing the reservoir pressure to the high and low pressure
values.
[0079] However, a different fluid may be injected for increasing the
reservoir pressure to the high pressure value than the fluid injected when
decreasing the reservoir pressure to the low pressure value. In an example,
the
heated fluid injected through the injection well when increasing the reservoir
pressure to the desired high pressure value may be a mixture of steam and one
or more solvents, whereas the heated fluid injected through the injection well
when lowering the reservoir to the desired low pressure value may be steam
only. In this example, once the desired high pressure value is reached,
solvent
injection ceases.
[0080] In another example, the heated fluid injected through the
injection
well during pressure cycling may be steam only. In this example, solvent must
be present in reservoir in order for the pressure cycling to increase
production
rates due to increased solvent solubility. The solvent within the reservoir
may be
present due to solvent injected during the production stage prior to pressure
cycling, or during the start-up stage, or both.
[0081] The high pressure value and the low pressure value are chosen such
that a difference between the high and low pressure values is at least about
25%
of the high pressure value. In an example, the difference between the high and
low pressure values is between about 25% and about 75%.
[0082] In some examples, the values of the high and low pressure values
may be varied between iterations such that the difference between the high and
low pressure values may be different during different iterations of pressure
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cycling. Alternatively, in another example, the values of the high and low
pressure values may be varied between cycles such that the difference between
the high and low pressure values remains constant.
[0083] The maximum pressure that may be utilized for the high pressure
value is the maximum operating pressure (MOP) of the reservoir. The MOP may
be, for example, set by the relevant regulatory authority such as, for
example,
the Alberta Energy Regulator (AER) for reservoirs located in Alberta, Canada.
The MOP is a function of reservoir depth, reservoir geological
characteristics, the
selected recovery process and the strength of the cap rock that is used for
containment. Typically, the MOP may be approximately 7000 kPa.
[0084] The minimum pressure that may be utilized for the low pressure
value generally is the lowest pressure that facilitates producing fluids
through the
production well up to the surface.
[0085] In addition, the high pressure value and low pressure value may be
limited by reservoir conditions. For example, the high and low pressure values
may be limited by so called "thief zones", in the vicinity of the injection
and
production well pair. Thief zones may include bottom water, top water, a
depleted gas cap, an intact gas cap, or any combination thereof. In cases in
which such thief zones exist, the high pressure value should not be so high
that
injected solvent or steam enters into the thief zones in a significant amount,
whereas the low pressure value should not be so low that fluids from the thief
zone enter into the vapor chamber in a significant amount.
[0086] In practice, the minimum low pressure value utilized in pressure
cycling may be at least about 25% of the high pressure value. In an example,
the low pressure value may be not greater than about 75% of the high pressure
value. Desirably, the low pressure value may be between about 50% and about
75% of the high pressure value.
[0087] In general, the time taken to adjust the reservoir pressure
between
the high and low pressure values is desirably as short as is feasible. For
example, the time to reduce the reservoir pressure from the high pressure
value
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to the low pressure value may be less than 2 days, and desirably less than 1
day.
[0088] In some examples, the rate of injection of heated fluids may be
adjusted as soon as the desired high or low pressure value is reached.
[0089] Alternatively, once reached, the high pressure value, or the low
pressure value, or both may be maintained for a particular time period. For
example, the high pressure value may be maintained for a first length of time,
and the low pressure value may be maintained for a second length of time. The
time periods for maintaining the high pressure value and the low pressure
value
may be the same for a particular cycle, or may different. In addition, the
time
periods may vary from cycle to cycle. For example, later cycles may maintain
the high and low pressures for time periods that are longer than in previous
cycles.
[0090] Because the relative amount of solvent utilized in a pressure
cycling
steam driven solvent process is low relative to the amount of steam, the
impact
of the time duration of the high or low pressure values on increased
production
rates may be less pronounced than in the case of pressure cycling during a
hybrid solvent process, which utilizes relatively higher concentrations of
solvents,
as discussed in more detail below.
[0091] Referring to FIG. 3, a graph shows the measured pressure within an
injection well 300, which corresponds to the reservoir pressure, and the
measured rate of oil production from a production well 301 as a function of
time
in a SAP utilizing an injection well and production well configuration similar
to
FIG. 1. The vertical dotted line indicates the point in time at which solvent
(10
wt% butane) injection begins. FIG. 3 shows a time period 302 of approximately
one year during which the injection pressure was increased from 2500 kPa to
3000 kPa, after which the injection pressure was reduced and maintained
between 2000 kPa to 2300 kPa. Arrow 304 in FIG. 3 shows that the oil
production rate increased significantly approximately six months after the
time
period 302.
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[0092] Referring to FIG. 4, a graph shows the measured pressure within an
injection well 400, which corresponds to the reservoir pressure, and the
measured rate of oil production 401 from a production well as a function of
time
in another SAP utilizing an injection well and production well configuration
similar
to FIG. 1. The vertical dotted line indicates the point in time at which
solvent
(10 wt% butane) injection begins.
[0093] A spike 402 in the measured injection pressure corresponds to a
time period of about 4 weeks during which the operating pressure of an
injection
well was increased from 2400kPa to 2900kPa by increasing a rate of injection
of
a mixture of steam and solvent through the injection well. The operating
pressure was then decreased to 2500kPa about 2 weeks later by decreasing the
rate of injection of the mixture of steam and solvent through the injection
well.
A spike 408 in the measured rate of oil production, corresponding to an oil
rate
increase from about 100 tons/day to about 200 tons/day was then observed.
This oil rate spike 408 was believed to be correlated with injection pressure
spike
402. The operating pressure of the injection well was increased again,
corresponding to a second spike 404 in the measured injection pressure several
weeks after the first pressure spike 402. The second pressure spike 404 was
followed by a second spike 410 in the measured oil production.
[0094] FIG. 5 through FIG. 8 show the results of simulations performed
for
various hydrocarbon recovery processes: SAGD without solvent injection or
pressure cycling, a steam driven solvent process without pressure cycling, and
a
steam driven solvent process with pressure cycling. The simulations performed
utilized a half-element of symmetry, dead oil, 2D reservoir simulation. A
summary of the reservoir model input parameters are shown in the following
table:
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PAT 104239-1
Item Input Units/Comments
Fluid Inputs
Phases Aqueous, Oleic,Vapor Three phases
Components Water, Bitumen, Methane, Four components
Butane
Reservoir Inputs
Grid number 50,1,30 2D Cartesian grid
Grid Size 50*1,1*2,30*0.8 Meter
Permeability 5, 5, 4 Darcy
Porosity 0.33
Initial Pressure 2200 kPa
Initial Temperature 11 Degree C
Soi, Swi 0.8, 0.2 No initial mobility to
Water
[0095] For the SAGD
without solvent injection or pressure cycling
simulation and the steam driven solvent process without pressure cycling
simulation, the injection pressure was maintained at constant 2600 kPa. In the
steam driven solvent process with and without pressure cycling simulations,
solvent injection was commenced at 90 days utilizing a mixture of steam with
butane at 10 wt% of the mixture.
[0096] In the pressure cycling steam driven solvent process simulation,
the
injection pressure was cycled between a low pressure value of 2600 kPa and a
high pressure value of 3000 kPa. The pressure cycling steam driven solvent
process simulation data presented in FIG. 5 through FIG. 8 shows three
pressure
cycles in which the pressure was increased to the high pressure value over a
period of 1 day, then maintained at the high pressure value for 1 day, then
dropped immediately, i.e., in less than 1 day, to the low pressure value and
was
maintained at the low pressure value for approximately 100 days before the
next
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cycle began by increasing the pressure to the high pressure value. In
addition,
during the pressure cycles, solvent injection was stopped when the high
pressure
value was reached, i.e., during pressure ramp-down, and was resumed when the
low pressure value was reached, i.e., during ramp-up.
[0097] FIG. 5 is a graph showing the simulated data of the cumulative
steam to oil ratio (CSOR) for SAGD without pressure cycling and solvent
injection
500, a steam driven solvent process without pressure cycling 502, and a
pressure cycling steam driven solvent process 504 as a function of time. FIG.
5
shows that the CSOR for the steam driven solvent process without pressure
cycling 502 is 30% lower than the CSOR for SAGD without pressure cycling and
solvent injection 500. The CSOR for the pressure cycling steam driven solvent
process 504 is 13% lower than the CSOR for SAGD without pressure cycling and
solvent injection 500.
[0098] FIG. 6 shows the rates of hydrocarbon production for the three
simulated hydrocarbon recovery processes shown in FIG. 5. In FIG. 6, these are
shown as: SAGD without pressure cycling or solvent injection 600, a steam
driven solvent process without pressure cycling 602, and a pressure cycling
steam driven solvent process 604 as a function of time. FIG. 6 shows that both
the steam driven solvent process without pressure cycling 602 and the pressure
cycling steam driven solvent process 604 have higher rates of hydrocarbon
production than SAGD without pressure cycling or solvent injection 600.
However, when the solvent injection is stopped in the pressure cycling steam
driven solvent process simulation 604, i.e., when pressure is ramped down, the
oil rate during the pressure cycling steam driven solvent process becomes
lower
than during the steam driven solvent process without pressure cycling 602.
[0099] FIG. 7 shows cumulative hydrocarbon production for the three
simulated hydrocarbon recovery processes shown in FIG. 5 and FIG. 6. In FIG.
7,
these are shown as: SAGD without pressure cycling or solvent injection 700, a
steam driven solvent process without pressure cycling 702, and a pressure
cycling steam driven solvent process 704 as a function of time. FIG. 7 shows
that the simulated cumulative hydrocarbons produced after 3 cycles of the
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pressure cycling steam driven solvent process 704 is nearly the same as the
cumulative hydrocarbons produced in the steam driven solvent process without
pressure cycling 702.
[00100] FIG. 8 is a graph showing the cumulative amount of solvent
injected
for the two simulated SAPs shown in FIG. 5 through FIG. 7. In FIG. 8, these
are
shown as: the steam driven solvent process without pressure cycling 802 and
the
pressure cycling steam driven solvent process 804. FIG. 8 shows that the
amount of solvent injected after 3 cycles in the pressure cycling steam driven
solvent process 804 simulation is about 25% of the solvent used in the steam
driven solvent process without pressure cycling 802. Thus the pressure cycling
steam driven solvent process may have improved economics compared to the
steam driven solvent process without pressure cycling, as much less solvent
may
be injected and may remain in the reservoir in the pressure cycling process.
[00101] From the simulation results, the pressure cycling steam driven
solvent process is able to produce approximately the same amount of oil as the
steam driven solvent process without pressure cycling while injecting much
less
solvent, resulting in lower cost. Though the simulated CSOR in the pressure
cycling steam driven solvent process is higher than that in the steam driven
solvent process without pressure cycling, it is 13% lower than the simulated
CSOR in SAGD without pressure cycling and solvent injection.
Pressure Cycling in a Hybrid Solvent Process
[00102] Pressure cycling may be utilized in a hybrid solvent process in
which
the amount of solvent injected with the steam may be greater than in a steam
driven solvent process as described above. In an example, the amount of
solvent injected in the pressure cycling in a hybrid solvent process may be
between about >20 wt% of the mixture of solvent and steam and about 80 wt%
of the mixture, and desirably the amount of solvent is about 50 wt%. In
another
example, the amount of solvent injected may be between about 40 wt% and
about 80 wt% of the mixture of solvent and steam.
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[00103] A pressure cycling hybrid solvent process is performed after the
vapor chamber has made contact with a ceiling formation of the reservoir, as
shown in (c) of FIG. 2. In addition, prior to initiating a pressure cycling
hybrid
solvent process, it may be desirable that no solvent, or very small amounts of
solvent, is present in the reservoir. For the purpose of this disclosure, a
significant amount of solvent injected into the reservoir is greater than
about
20% solvent saturation, such that a pressure cycling hybrid solvent process
may
be performed if the solvent saturation in the reservoir is less than or equal
to
about 20%. Solvent saturation is the volume of solvent in the reservoir at
reservoir conditions divided by the total volume of solvent, gas, steam, oil
and
water at reservoir conditions. Without wishing to be bound by any particular
theory, injecting at higher concentrations of solvents means less heat via
steam
is injected into the reservoir prior to initiating a pressure cycling hybrid
solvent
process. Having less heat in the reservoir will result in the solvent being
less
soluble in the hydrocarbons, which will reduce the benefits of any hybrid
solvent
process in which a relatively high amount, e.g., greater than 20 wt%, of
solvent
is already injected into the reservoir.
[00104] Thus, for example, in pressure cycling in a hybrid solvent
process,
after the plateau stage is reached by injecting steam only, a heated fluid is
injected into the reservoir through the injection well.
[00105] The rate of injection of the heated fluid may be increased to
cause
the pressure in the reservoir to increase to a desired high pressure value.
Once
a sufficiently high pressure is reached, the rate of injection of the heated
fluid
may be reduced to cause the reservoir pressure to be decreased to a desired
low
pressure value. Once a sufficiently low pressure is reached, the rate of
injection
may be increased again, and so forth, in order to cycle between high and low
pressure values.
[00106] Alternatively, during the initial cycle, the rate of injection of
the
heated fluid may be reduced to cause the pressure in the reservoir to first be
lowered to a desired low pressure value, then the rate may be increased to
increase the reservoir pressure to a desired high pressure value.
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[00107] The heated fluid injected during a pressure cycling hybrid solvent
process may be a mixture of steam and one or more solvents. The solvents
utilized for a pressure cycling hybrid solvent process may be selected from
alkanes having 2 to 9 carbon atoms. The solvent utilized may be one alkane or
a
combination of alkanes. A mixture of different solvents may be utilized in a
pressure cycling hybrid solvent process when, for example, utilizing a single
solvent may not be feasible depending on solvent supply. Examples of solvents
that may be utilized in a pressure cycling hybrid solvent process include
natural
gas condensate, liquefied petroleum (also known as liquefied petroleum gas),
hexane, pentane, propane, butane, and ethane.
[00108] In addition, non-condensing gases, such as, for example, methane,
air, carbon dioxide, or nitrogen, or any combination thereof, may be included
in
the heated fluid injected into the reservoir through the injection well.
[00109] The high pressure value and the low pressure value are chosen such
that a difference between the high and low pressure values is at least about
25%
of the high pressure value. In an example, the difference between the high and
low pressure values is between about 25% and about 75%. In some examples,
the values of the high and low pressure values may be varied between
iterations
such that the difference between the high and low pressure values may be
different during different iterations of pressure cycling. Alternatively, in
another
example, the values of the high and low pressure values may be varied between
cycles such that the difference between the high and low pressure values
remains constant.
[00110] As with the above description with respect to pressure cycling
steam
driven solvent processes, the maximum pressure that may be utilized for the
high pressure value in a pressure cycling hybrid solvent process is the MOP of
the reservoir. In addition, the maximum pressure may be determined based on
the presence of certain reservoir conditions, such as thief zones in the
vicinity of
the injection and production well pair, such that the high pressure value is
not so
high that injected steam and solvent may enter the thief zones in a
significant
amount.
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[00111] Similar to pressure cycling steam driven solvent processes, the
minimum low pressure value utilized in a pressure cycling hybrid solvent
process
is a pressure value that is above the lowest pressure that facilitates
producing
fluid to the surface. In addition, the low pressure value may be determined
based on the presence of reservoir conditions, such as thief zones in the
vicinity
of the injection and production well pair, such that the low pressure value is
not
so low that fluids from any thief zones enter the vapor chamber in a
significant
amount.
[00112] In practice, the minimum low pressure value utilized in pressure
cycling is at least about 25% of the high pressure value. In an example, the
low
pressure value may be not greater than about 75% of the high pressure value.
Desirably, the low pressure value is between about 50% and about 75% of the
high pressure value.
[00113] In general, the time taken to adjust the reservoir pressure
between
the high and low pressure values is desirably as short as is feasible. For
example, the time to reduce the reservoir pressure from the high pressure
value
to the low pressure value may be less than 2 days, and desirably less than 1
day.
[00114] The rate of injection of heated fluids may be adjusted as soon as
the desired high or low pressure value is reached. Alternatively, one or both
of
the high and low pressure values may be maintained for a time period after the
respective high or low pressure value is reached. Because the solvent
concentrations utilized in a pressure cycling hybrid solvent process are
higher
than utilized in a pressure cycling steam driven solvent process, maintaining
the
high and low pressure values for a time duration in each pressure cycle will
have
a greater effect in a pressure cycling hybrid solvent process compared to a
pressure cycling steam driven solvent process. In addition, heat propagates to
the edge 210 of the vapor chamber 208 more quickly in a pressure cycling steam
driven solvent process than in a pressure cycling hybrid solvent process due
to
the higher concentration of steam that is injected in a pressure cycling steam
driven solvent process. Because heat propagates to the edge 210 more quickly
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in a pressure cycling steam driven solvent process, the time period for
maintaining a high pressure value in pressure cycling steam driven solvent
process may desirably be set shorter than the time period that the high
pressure
value is maintained for in a pressure cycling hybrid solvent process.
[00115] Therefore, in an example, the high pressure value, or the low
pressure value, or both may be maintained for a particular time duration. For
example, once the pressure in the reservoir is increased to the high pressure
value, the high pressure value may be maintained for a particular time period,
rather than immediately decreasing the rate of injection of the heated fluid
to
lower the pressure to the low pressure value again. Similarly, once the
pressure
is decreased to the low pressure value, the low pressure value may be
maintained for a particular time period, rather than immediately increasing
the
rate of injection of the heated fluid to increase the pressure to the high
pressure
value again.
[00116] Desirably, the high pressure value and the low pressure value may
both be maintained for the same period of time during a particular cycle. In
other examples the time period for maintaining the high pressure value may be
different from the time period for maintaining the low pressure value.
[00117] FIG. 9 shows a graph showing simulation data of cumulative oil
production as a function of time for a pressure cycling hybrid solvent process
performed with the high and low pressure values maintained for various time
durations. The simulation was performed utilizing a steam and solvent mixture
containing 50 wt% propane, a high pressure value of 5000 kPa and a low
pressure value of 3250 kPa.
[00118] Plot 902 shows the cumulative oil production for a duration of 5
days for the high and low pressure values. Plot 904 shows the cumulative oil
production for a duration of 15 days for the high and low pressure values.
Plot
906 shows the cumulative oil production for a duration of 30 days for the high
and low pressure values. Plots 908 and 910 show the cumulative oil production
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for constant pressure at the high pressure value and the low pressure value,
respectively.
[00119] The simulation results in FIG. 9 show that utilizing a time
duration
of 15 days (plot 904) for maintaining the high and low pressure values
resulted
in the highest overall cumulative oil production. However, the time duration
of
30 days (plot 906) resulted in the lowest solvent to oil ratio (SolOR).
[00120] In an example, the time period for maintaining the reservoir
pressure at the high and low pressure values in a pressure cycling hybrid
solvent
process may be between about 5 days and about 90 days, and desirably the time
period may be about 30 days. Based on the simulation results, a 30 day time
period for maintaining the high and low pressure values may be desirable
because this results in a lower SolOR, and the spikes in cumulative oil rate
are
more pronounced than time periods of 5 and 15 days.
[00121] As noted above, the time periods for maintaining the pressure at
high and low pressure values in a pressure cycling steam driven solvent
process
are desirably shorter than for a pressure cycling hybrid solvent process due
to
the quicker propagation of temperature in the vapor chamber in a pressure
cycling steam driven solvent process compared to a pressure cycling hybrid
solvent process.
[00122] In addition, the time periods for maintaining the high and low
pressure values may vary from cycle to cycle. In an example, later cycles may
maintain the high and low pressures for time periods that are longer than in
previous cycles. As time passes and the vapor chamber expands, the pressure of
the reservoir may be maintained at the high pressure value for longer time
periods without causing a significant temperature increase in the mixing zone
at
the edge of the vapor chamber compared to earlier cycles. Without being
limited
to theory, longer time periods for maintaining the high and low pressure
values
may have a greater effect on increasing solvent solubility in the hydrocarbons
at
higher concentrations of co-injected solvent, for example about greater than
20
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wt%, as compared to lower concentrations, for example less than or equal to
about 20 wt%.
Producing Hydrocarbons utilizing Pressure Cycling in a Solvent-Aided
Process
[00123] Referring now to FIG. 10, a process for producing hydrocarbons
from a subterranean hydrocarbon-bearing formation utilizing solvents is shown
in
FIG. 10. The process illustrated in FIG. 10 may be performed as part of a SAP
utilizing a production well and an injection well. The injection well includes
a
segment extending substantially horizontally into the reservoir and the
production well includes a segment extending substantially horizontally into
the
reservoir. The horizontal segment of the production well is vertically offset
from
and extends substantially parallel to the horizontal segment of the injection
well,
similar to the production well 100 and the injection well 108 described above
and
illustrated in FIG. 1.
[00124] At 1002, hydrocarbons in a near-wellbore region of the reservoir
are
heated during a start-up stage to establish fluid communication between the
injection well and the production well. As described above, any suitable start-
up
process for heating the hydrocarbons in the near-wellbore region and
establishing fluid communication between the injection well and the production
well may be utilized including, for example, circulating heated fluids in one
or
both of the injection and production wells, injecting heated fluid into the
reservoir through one or both injection and production wells, and heating by
placing heaters into one or both of the injection and production wells.
[00125] When the process of FIG. 10 is performed as part of a pressure
cycling steam driven solvent process, any fluids injected during start-up may
comprise injecting a solvent, or a mixture of steam and solvent, into the
reservoir. When the process of FIG. 10 is performed as part of a pressure
cycling hybrid solvent process, any fluid injected into the reservoir during
start-
up is desirably steam only such that the fluid does not contain a significant
amount of solvent. As described above, a significant amount of solvent
injected
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during the start-up stage and/or the production stage prior to initiating a
pressure cycling hybrid solvent process is an amount that results in greater
than
about 20% solvent saturation in the reservoir.
[00126] During the production stage, after fluid communication between the
injection and production wells is established and the start-up stage is ended,
hydrocarbons in the reservoir are produced to the surface through the
production
well at 1004.
[00127] Optionally, at 1006, the production stage may include forming a
chamber that results over time from injection of a first fluid into the
reservoir.
As noted above, if the process of FIG. 10 is performed as part of a pressure
cycling steam driven solvent process, pressure cycling may be initiated at any
point during the production stage and, desirably, when the vapor chamber has
contacted a formation ceiling of the reservoir. In a pressure cycling steam
driven
solvent process, the first fluid that is injected during the production stage
prior to
pressure cycling may be steam, a mixture of steam and solvent, or solvent
only.
[00128] Alternatively, pressure cycling in a pressure cycling steam driven
solvent process may begin immediately after start-up is completed, before
significant, i.e., more than nominal, vapor chamber formation, and when fluid
communication is established between the injection and production wells. In
this
case, optional step 1006 may be skipped.
[00129] If the process of FIG. 10 is performed as part of a pressure
cycling
hybrid solvent process, pressure cycling begins after the plateau stage is
reached, i.e., when the vapor chamber formed at 1006 reaches the formation
ceiling of the reservoir. As described above, in this case the first fluid
injected at
1006 is steam and does not contain a significant amount of solvent.
[00130] At 1008, while producing hydrocarbons through the production well,
a second fluid is injected into the reservoir through the injection well at a
first
rate to adjust a pressure in the reservoir to a first pressure value. After
reaching
the first pressure value, a third fluid is injected into the reservoir through
the
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injection well at 1010. The third fluid is injected at 1010 at a second rate
to
adjust the pressure in the reservoir to a second pressure value.
[00131] In an example, a difference between the first pressure value and
the second pressure value is not less than about 25% of the higher of the
first
pressure value and the second pressure value. The difference may be not
greater than about 75% of the higher of the first and second pressure values.
Desirably, the difference between the first pressure and the second pressure
may
be between about 50% and 75% of the higher of the first and second pressure
values.
[00132] In general, the time taken to adjust the reservoir pressure to the
first pressure value at 1008 and to the second pressure value at 1010 should
be
as short as feasible. For example, the time between the reservoir pressure
changing from the first pressure value to the second pressure value may be
less
2 days, and desirably less than 1 day.
[00133] Generally, the second fluid and the third fluid may be the same.
For
example, in both a pressure cycling steam driven solvent process and a
pressure
cycling hybrid solvent process, generally the second fluid and the third fluid
may
each have the same composition of steam and solvent. Additionally, as
described above, in some examples a pressure cycling steam driven solvent
process may be performed in which the second fluid and third fluid are both
steam only when, for example, solvent is injected into the reservoir during
start-
up, earlier during the production stage, or both.
[00134] However, in some instances the second fluid may be different from
the third fluid. For example in a pressure cycling steam driven solvent
process, a
mixture of steam and solvent may be injected when the pressure of the
reservoir
is being increased to a high pressure value, and steam only may be injected
when the pressure in the reservoir is being decreased to a lower pressure
value.
[00135] In an example, the first pressure value may be a high pressure
value, and the second pressure value may be a low pressure value that is lower
than the high pressure value. In this example, the pressure in the reservoir
is
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increased at 1008 and decreased at 1010. Alternatively, the first pressure
value
may be the low pressure value and the second pressure value may be the high
pressure value. In this example, the pressure of the reservoir is decreased at
1008, then increased at 1010.
[00136] As described above, the maximum pressure that may be utilized for
the greater of the first and second pressure values is the MOP of the
reservoir,
for example, that is allowed by the relevant regulatory body. However, the
maximum pressure may be limited by unique reservoir conditions such as, for
example, thief zones in the reservoir in the vicinity of the injection and
production well pair. The minimum pressure value that may be utilized for the
lesser of the first and second pressure values is a pressure value that is
above
the lowest pressure that facilitates producing fluid to the surface, and may
be
limited by unique reservoir conditions such as, for example, thief zones in
the
reservoir in the vicinity of the injection and production wells.
[00137] As described above, adjusting the pressure at 1008 may include
maintaining the first pressure value for a time period, and adjusting the
pressure
at 1010 may include maintaining the second pressure value for a time period.
As
described above, maintaining the first and second pressure values will have a
greater effect on the rate of production of hydrocarbons in a pressure cycling
hybrid solvent process than in a pressure cycling steam driven solvent
process.
Therefore, when the process of FIG. 10 is performed as part of a pressure
cycling
hybrid solvent process, the first pressure value at 1008 and the second
pressure
value at 1010 are desirably maintained for a time period. The time period may
be between 5 and 90 days. Further, as described above, the time period may
vary over time such that subsequent iterations of steps 1008 and 1010 may have
longer time periods than earlier iterations. For example, at the beginning of
the
pressure cycling process, the first and second pressures may be both
maintained
for about 30 days, while the first and second pressure values towards the end
of
the SAP production stage may be maintained for about 90 days.
[00138] At 1012, a determination whether to continue pressure cycling is
made. The determination at 1012 may be based on, for example, whether it is
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economical to continue cycling the pressure between the first and second
pressure values. In an example, it may be determined that continuing to cycle
the pressure is not economical when the operating costs of the pressure
cycling
steam driven solvent process or pressure cycling hybrid solvent process are
greater than the value of the oil being produced. The operating costs include,
for
example, cost to produce steam, cost for the utilized solvents, costs with
respect
to recycling solvents produced through the production well. Alternatively, or
additionally, the determination at 1012 may be based on a determination
whether the well has reached the end of the production stage and a wind-down
or blow-down stage should be initiated.
[00139] If the determination at 1012 is yes, then the process continues to
1008 such that pressure cycling between the first and second pressure values
is
repeated at 1008 and 1010 respectively.
[00140] If the determination at 1012 is no, then the process ends. Ending
the process may include initiating a wind-down stage, as described above.
Alternatively, ending the process may include resuming a SAP or a SAGD
production process without pressure cycling.
[00141] The present disclosure provides processes for producing
hydrocarbons from a subterranean formation utilizing cycling of the pressure
in
the reservoir between a high pressure value and a low pressure value. Cycling
between a high pressure value and a low pressure value is shown to increase
the
rate of oil production at the production well in a SAP compared to a SAP
performed at substantially constant pressure or compared to SAGD, while
reducing the solvent to oil ratio, and reducing cumulative solvent injected
into
the reservoir, compared to operating utilizing a constant pressure. Reducing
the
amount of solvent utilized while increasing the rate of hydrocarbon production
results in a more cost effective process for producing hydrocarbons from a
subterranean formation.
[00142] The described embodiments are to be considered in all respects
only
as illustrative and not restrictive. The scope of the claims should not be
limited
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by the preferred embodiments set forth in the examples, but should be given
the
broadest interpretation consistent with the description as a whole. All
changes
that come with meaning and range of equivalency of the claims are to be
embraced within their scope.
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