Note: Descriptions are shown in the official language in which they were submitted.
INTEGRATED PROCESSES UTILIZING STEAM AND SOLVENT FOR BITUMEN
RECOVERY
Technical Field
[0001] The present disclosure relates generally to methods of recovering
hydrocarbons from underground reservoirs, and more specifically to integrated
processes
utilizing steam and solvent for recovering hydrocarbons from underground
reservoirs.
Background
[0002] This section is intended to introduce various aspects of the art
that may be
associated with the present disclosure. This discussion aims to provide a
framework to
facilitate a better understanding of particular aspects of the present
disclosure.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as an admission of prior art.
[0003] Historically commercial in-situ oil sands processes have included:
cyclic
steam stimulation (CSS), steam assisted gravity drainage (SAGD), and steam-
flood (SF).
These processes have extracted oil from underground reservoirs using steam.
The next
generation of in-situ processes may use solvent-steam or pure solvent to
extract oil from
similar reservoirs. The benefits of these processes are lower energy
intensity, lower water
usage, ability to access previously uneconomic resource, and higher reservoir
recovery
rates.
[0004] In steam-based processes, increased temperatures in the reservoir
lower
the viscosity of oil allowing it to flow and be produced. In solvent-based
process, the
solvent dilutes the oil and lowers its viscosity to allow it to flow.
[0005] Steam-based oil sands extraction processes use water sourced from
nearby local supplies to fill central processing facilities (CPF). These
sources of water
may include: surface water, aquifers; freshwater or brackish, and produced
water from
other operations. For steam-based processes, the CPF is generally sized for
the
resources that are available and to bring steam online quickly.
[0006] In contrast, as production or extraction of solvent may not be
possible at the
oil extraction location, solvent generally needs to be transported to site.
Transportation
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can be by truck, train, or pipeline. Once the solvent has been brought to
site, a high
percentage of solvent (>75%) will be recycled and continuously used in the
solvent
processes. There is a commercial tradeoff with bringing solvent to site. The
supply must
be sized to balance cost, quantity required, and delivery dependability.
Therefore, due to
inability to bring large quantity of solvent to site initially, there will be
a longer time period
for solvent processes to achieve plateau injection rates. This slower ramp to
peak solvent
injection leads to lower oil production and a decrease in economics.
[0007] Previous studies have shown that steam-based process and solvent-
based
processes can target the same resource. However, steam-based processes can
have
inferior performance in solvent specific resources due to thinner pay, lower
bitumen
saturation, and pressure restrictions and/or limitations. One of the primary
reasons is due
to heat losses to non-pay (e.g. cap rock, low bit-sat sands). The performance
downgrade
with steam processes would be more pronounced in mid-to-late life as the steam
chamber
grows. For solvent-based processes, heat in the near wellbore area could
improve
performance.
[0008] Accordingly, there is a need for improved methods of enhancing
cyclic
solvent processes with steam for bitumen recovery from oil sands reservoirs.
Summary
[0009] The present disclosure described methods of recovering bitumen from
an
underground reservoir. According to at least one broad aspect, a method of
recovering
bitumen from an underground reservoir penetrated by a wellbore, the wellbore
including
a casing, is described, the method includes injecting a first mobilizing fluid
through the
wellbore into the reservoir, the first mobilizing fluid including steam;
shutting in the first
mobilizing fluid that is in the reservoir to lower a viscosity of at least a
portion of the
bitumen in the reservoir; holding the first mobilizing fluid in the reservoir
to lower a
viscosity of at least a portion of the bitumen in the reservoir; recovering
bitumen of lowered
viscosity from the reservoir; during a subsequent step of injecting first
mobilizing fluid into
the reservoir, detecting a casing integrity issue in the wellbore; in response
to detecting
the casing integrity issue in the wellbore, injecting a second mobilizing
fluid through the
wellbore into the reservoir to reduce a pressure of the reservoir and to
reduce thermal
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..
cycling, the second mobilizing fluid including a hydrocarbon solvent; shutting
in the
second mobilizing fluid that is in the reservoir; holding the second
mobilizing fluid in the
reservoir to lower viscosity of at least a portion of the bitumen in the
reservoir; and
recovering bitumen of lowered viscosity from the reservoir.
[0010] According to another aspect, the second mobilizing fluid
differs from the first
mobilizing fluid.
[0011] According to another aspect, the steps of injecting the
first mobilizing fluid
through the wellbore into the reservoir, shutting in the first mobilizing
fluid that is in the
reservoir to lower the viscosity of at least a portion of the bitumen in the
reservoir, and
recovering bitumen of lowered viscosity from the reservoir are part of a
cyclic steam
stimulation (CSS) process for recovering bitumen from the underground
reservoir.
[0012] According to another aspect, the steps of injecting the
second mobilizing
fluid through the wellbore into the reservoir, shutting in the second
mobilizing fluid that is
in the reservoir, holding the second mobilizing fluid in the reservoir and
recovering
bitumen of lowered viscosity from the reservoir are part of a cyclic solvent
process (CSP)
for recovering bitumen from the underground reservoir.
[0013] According to another aspect, detecting the at least one
casing integrity issue
is by a monitoring system.
[0014] According to another aspect, the monitoring system is a
passive seismic
monitoring system, a differential flow pressure monitoring system and/or an N2
soak
monitoring system.
[0015] According to another aspect, detecting the at least one
casing integrity issue
is by performing casing integrity checks.
[0016] According to another aspect, the casing integrity checks
include measuring
ovalities in the casing.
[0017] According to another aspect, the casing integrity issue
includes a decline in
a structural integrity of an intermediate casing of the wellbore.
[0018] According to another aspect, the method further includes,
after detecting
the casing integrity issue and prior to injecting the second mobilizing fluid
through the
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wellbore into the reservoir, shutting in the first mobilizing fluid in the
reservoir and holding
the first mobilizing fluid in the reservoir.
[0019] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir after detecting the casing integrity issue is for a period of
time in a range of
about 24 to 48 hours.
[0020] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir after detecting the casing integrity issue includes analyzing
data collected
from the wellbore and/or the reservoir prior to detecting the casing integrity
issue to
confirm the casing integrity issue.
[0021] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir after detecting the casing integrity issue includes analyzing
data collected
from the wellbore and/or the reservoir after detecting the casing integrity
issue to confirm
the casing integrity issue.
[0022] According to another aspect, the method includes, after detecting
the casing
integrity issue and prior to injecting the second mobilizing fluid through the
wellbore into
the reservoir, recovering fluid from the reservoir to reduce the pressure of
the reservoir.
[0023] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir is for a period of time in a range of about 24 to 48 hours.
[0024] According to another aspect, the step of holding the second
mobilizing fluid
in the reservoir is for a period of time in a range of about 24 to 48 hours.
[0025] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at a wellbore is described herein. The
method
includes injecting a first mobilizing fluid through the wellbore into the
reservoir, the first
mobilizing fluid including steam; shutting in the first mobilizing fluid that
is in the reservoir
to lower viscosity of at least a portion of the bitumen in the reservoir;
holding the first
mobilizing fluid in the reservoir to lower a viscosity of at least a portion
of the bitumen in
the reservoir; recovering bitumen of lowered viscosity from the reservoir;
during a
subsequent step of injecting first mobilizing fluid into the reservoir,
detecting at least one
fluid excursion issue from the wellbore; in response to detecting the at least
one fluid
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excursion issue from the wellbore, injecting a second mobilizing fluid into
the reservoir,
the second mobilizing fluid including a hydrocarbon solvent; shutting in the
second
mobilizing fluid that is in the reservoir; holding the second mobilizing fluid
in the reservoir
to lower viscosity of at least a portion of the bitumen in the reservoir; and
recovering
bitumen of lowered viscosity from the reservoir.
[0026] According to another aspect, the second mobilizing fluid differs
from the first
hydrocarbon fluid.
[0027] According to another aspect, the steps of injecting the first
mobilizing fluid
through the wellbore into the reservoir, shutting in the first mobilizing
fluid that is in the
reservoir to lower the viscosity of at least a portion of the bitumen in the
reservoir, and
recovering bitumen of lowered viscosity from the reservoir are part of a
cyclic steam
stimulation (CSS) process for recovering bitumen from the underground
reservoir.
[0028] According to another aspect, the steps of injecting the second
mobilizing
fluid through the wellbore into the reservoir, shutting in the second
mobilizing fluid that is
in the reservoir, holding the second mobilizing fluid in the reservoir and
recovering
bitumen of lowered viscosity from the reservoir are part of a cyclic solvent
process (CSP)
for recovering bitumen from the underground reservoir.
[0029] According to another aspect, the detecting the at least one fluid
excursion
issue is by monitoring a pressure of the reservoir via one or more observation
wellbores
offset from a production pad including the wellbore and detecting an increase
in the
pressure of the reservoir of target reservoir or other geologic zone.
[0030] According to another aspect, the detecting the at least one fluid
excursion
issue is by analyzing injection and production pressure profiles.
[0031] According to another aspect, the method also includes, after
detecting the
fluid excursion issue and prior to injecting the second mobilizing fluid
through the wellbore
into the reservoir, shutting in the first mobilizing fluid in the reservoir
and holding the first
mobilizing fluid in the reservoir.
[0032] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir is for a period of time in a range of about 24 to 48 hours.
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[0033] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir includes performing diagnostic work to confirm the fluid
excursion issue in
the wellbore.
[0034] According to another aspect, the method also includes, after
detecting the
fluid excursion issue and prior to injecting the second mobilizing fluid
through the wellbore
into the reservoir, recovering fluid from the reservoir to reduce the pressure
of the
reservoir.
[0035] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir is for a period of time in a range of about 24 to 48 hours.
[0036] According to another aspect, the step of holding the second
mobilizing fluid
in the reservoir is for a period of time in a range of about 24 to 48 hours.
[0037] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at least one well is described. The
method
includes injecting a first mobilizing fluid into the reservoir, the first
mobilizing fluid including
steam; shutting in the first mobilizing fluid that is in the reservoir to
lower viscosity of at
least a portion of the bitumen in the reservoir; holding the first mobilizing
fluid in the
reservoir to lower a viscosity of at least a portion of the bitumen in the
reservoir; recovering
bitumen of lowered viscosity from the reservoir; during a subsequent step of
injecting first
mobilizing fluid into the reservoir, detecting at least one pump issue in the
wellbore; in
response to detecting the at least one pump issue, injecting a second
mobilizing fluid into
the reservoir, the second mobilizing fluid including a hydrocarbon solvent;
shutting in the
second mobilizing fluid that is in the reservoir; holding the second
mobilizing fluid in the
reservoir to lower viscosity of at least a portion of the bitumen in the
reservoir; and
recovering bitumen of lowered viscosity from the reservoir.
[0038] According to another aspect, the second mobilizing fluid differs
from the first
mobilizing fluid.
[0039] According to another aspect, the steps of injecting the first
mobilizing fluid
through the wellbore into the reservoir, shutting in the first mobilizing
fluid that is in the
reservoir to lower the viscosity of at least a portion of the bitumen in the
reservoir, and
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recovering bitumen of lowered viscosity from the reservoir are part of a
cyclic steam
stimulation (CSS) process for recovering bitumen from the underground
reservoir.
[0040] According to another aspect, the steps of injecting the second
mobilizing
fluid through the wellbore into the reservoir, shutting in the second
mobilizing fluid that is
in the reservoir, holding the second mobilizing fluid in the reservoir and
recovering
bitumen of lowered viscosity from the reservoir are part of a cyclic solvent
process (CSP)
for recovering bitumen from the underground reservoir.
[0041] According to another aspect, the detecting pump issues in the at
least one
well includes detecting a low fillage rate of a pump of the well.
[0042] According to another aspect, the detecting pump issues in the at
least one
well includes detecting flashing of a fluid within a pump of the well.
[0043] According to another aspect, the detecting pump issues in the at
least one
well includes detecting a gaseous fluid in production tubing of the wellbore.
[0044] According to another aspect, the detecting pump issues in the at
least one
well includes detecting failure of a pump of the well.
[0045] According to another aspect, the method includes, after detecting
the at
least one pump issue and prior to injecting the second mobilizing fluid
through the
wellbore into the reservoir, shutting in the first mobilizing fluid in the
reservoir and holding
the first mobilizing fluid in the reservoir.
[0046] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir is for a period of time in a range of about 24 to 48 hours.
[0047] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir includes performing diagnostic work to confirm the at least one
pump issue
in the wellbore.
[0048] According to another aspect, the method includes, after detecting
the at
least one pump issue and prior to injecting the second mobilizing fluid
through the
wellbore into the reservoir, recovering fluid from the reservoir to reduce the
pressure of
the reservoir.
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[0049] According to another aspect, the step of holding the first
mobilizing fluid in
the reservoir is for a period of time in a range of about 24 to 48 hours.
[0050] According to another aspect, the step of holding the second
mobilizing fluid
in the reservoir is for a period of time in a range of about 24 to 48 hours.
[0051] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at least one well is described. The
wellbore
includes a casing. The method includes injecting a first mobilizing fluid
through the
wellbore into the reservoir, the first mobilizing fluid including steam;
shutting in the first
mobilizing fluid that is in the reservoir to lower a viscosity of at least a
portion of the
bitumen in the reservoir; holding the first mobilizing fluid in the reservoir
to lower a
viscosity of at least a portion of the bitumen in the reservoir; recovering
bitumen of lowered
viscosity from the reservoir; during a subsequent step of shutting in the
first mobilizing
fluid into the reservoir or holding the first mobilizing fluid in the
reservoir, detecting a
casing integrity issue in the wellbore; in response to detecting the casing
integrity issue
in the wellbore, injecting a second mobilizing fluid through the wellbore into
the reservoir
to reduce a pressure of the reservoir and to reduce thermal cycling, the
second mobilizing
fluid including a hydrocarbon solvent; shutting in the second mobilizing fluid
that is in the
reservoir; holding the second mobilizing fluid in the reservoir to lower
viscosity of at least
a portion of the bitumen in the reservoir; and recovering bitumen of lowered
viscosity from
the reservoir.
[0052] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at a wellbore is described The method
includes
injecting a first mobilizing fluid through the wellbore into the reservoir,
the first mobilizing
fluid including steam; shutting in the first mobilizing fluid that is in the
reservoir to lower
viscosity of at least a portion of the bitumen in the reservoir; holding the
first mobilizing
fluid in the reservoir to lower a viscosity of at least a portion of the
bitumen in the reservoir;
recovering bitumen of lowered viscosity from the reservoir; during a
subsequent step of
shutting in the first mobilizing fluid into the reservoir or holding the first
mobilizing fluid in
the reservoir, detecting at least one fluid excursion issue in the wellbore;
in response to
detecting the at least one fluid excursion issue from the wellbore, injecting
a second
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mobilizing fluid into the reservoir, the second mobilizing fluid including a
hydrocarbon
solvent; shutting in the second mobilizing fluid that is in the reservoir;
holding the second
mobilizing fluid in the reservoir to lower viscosity of at least a portion of
the bitumen in the
reservoir; and recovering bitumen of lowered viscosity from the reservoir.
[0053] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at least one well is described. The
method
includes injecting a first mobilizing fluid into the reservoir, the first
mobilizing fluid including
steam; shutting in the first mobilizing fluid that is in the reservoir to
lower viscosity of at
least a portion of the bitumen in the reservoir; holding the first mobilizing
fluid in the
reservoir to lower a viscosity of at least a portion of the bitumen in the
reservoir; recovering
bitumen of lowered viscosity from the reservoir; during a subsequent step of
shutting in
the first mobilizing fluid into the reservoir or holding the first mobilizing
fluid in the
reservoir, detecting at least one pump issue in the wellbore; in response to
detecting the
at least one pump issue, injecting a second mobilizing fluid into the
reservoir, the second
mobilizing fluid including a hydrocarbon solvent; shutting in the second
mobilizing fluid
that is in the reservoir; holding the second mobilizing fluid in the reservoir
to lower
viscosity of at least a portion of the bitumen in the reservoir; and
recovering bitumen of
lowered viscosity from the reservoir.
[0054] According to another aspect, the first mobilizing fluid is a steam-
dominated
mobilizing fluid.
[0055] According to another aspect, the first mobilizing fluid is steam
with a quality
between 0% and 100%.
[0056] According to another aspect, the first mobilizing fluid is steam
with a quality
of about 70%.
[0057] According to another aspect, the first mobilizing fluid is steam
having a
temperature above about 25 C.
[0058] According to another aspect, the first mobilizing fluid is steam
having a
temperature above about 200 C.
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[0059] According to another aspect, the first mobilizing fluid is steam
having a
temperature above about 325 C.
[0060] According to another aspect, the second mobilizing fluid is a
solvent.
[0061] According to another aspect, the second mobilizing fluid is one of:
a C2-C7
alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, and a gas plant
condensate
comprising alkanes, naphthenes, and aromatics.
[0062] According to another aspect, the first mobilizing fluid is about 75%
by mass
steam.
[0063] According to another aspect, the first mobilizing fluid is about 85%
by mass
steam.
[0064] According to another aspect, the first mobilizing fluid is about 95%
by mass
steam.
[0065] According to another aspect, the second mobilizing fluid is about
75% by
mass solvent.
[0066] According to another aspect, the second mobilizing fluid is about
85% by
mass solvent.
[0067] According to another aspect, the second mobilizing fluid is about
95% by
mass solvent.
[0068] According to another aspect, the first mobilizing fluid is about 75%
by mass
steam and the second mobilizing fluid is about 75% by mass solvent.
[0069] According to another aspect, the first mobilizing fluid is about 85%
by mass
steam and the second mobilizing fluid is about 85% by mass solvent.
[0070] According to another aspect, the first mobilizing fluid is about 95%
by mass
steam and the second mobilizing fluid is about 95% by mass solvent.
[0071] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at least one well is described herein.
The method
includes operating a first cyclic solvent process for recovering bitumen from
an
underground reservoir in the at least one well. The first cyclic solvent
process includes
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injecting a mobilizing fluid into the reservoir, the mobilizing fluid
including a hydrocarbon
solvent; shutting in the mobilizing fluid that is in the reservoir, holding
the mobilizing fluid
in the reservoir to lower viscosity of at least a portion of the bitumen in
the reservoir; and
recovering bitumen of lowered viscosity from the reservoir and, during a
subsequent
cyclic solvent process, when a pressure of the underground reservoir is less
than 50% of
a lithostatic pressure during the step of injecting the mobilizing fluid into
the reservoir,
converting the at least one well to be a producer well of a solvent flooding
process, where
one or more neighboring wells are injector wells and bitumen from the
underground
reservoir is produced from the at least one well.
[0072] According to another aspect, the mobilizing fluid includes steam,
and/or a
hydrocarbon solvent.
[0073] According to another broad aspect, a method of recovering bitumen
from
an underground reservoir penetrated by at least one well is described. The
method
includes operating a cyclic solvent process for recovering bitumen from an
underground
reservoir in the at least one well. The cyclic solvent process includes
injecting a first
mobilizing fluid into the reservoir, the first mobilizing fluid including a
hydrocarbon solvent;
shutting in the first mobilizing fluid that is in the reservoir to lower
viscosity of at least a
portion of the bitumen in the reservoir; and recovering bitumen of lowered
viscosity from
the reservoir. The method also includes providing an infill well in an unswept
region of the
underground reservoir formed between the at least one well and a neighboring
well
operating a cyclic solvent process; and operating a cyclic process for
recovering bitumen
from the underground reservoir in the infill well, the cyclic process
including injecting a
second mobilizing fluid into the reservoir, the second mobilizing fluid
including steam;
shutting in the second mobilizing fluid that is in the reservoir; holding the
second
mobilizing fluid in the reservoir to lower viscosity of at least a portion of
the bitumen in the
reservoir; and recovering bitumen of lowered viscosity from the reservoir.
[0074] According to another aspect, the step of injecting the second
mobilizing fluid
into the reservoir includes injecting the second mobilizing fluid into the
reservoir at a
pressure that is greater than 80% of a lithostatic pressure of the reservoir.
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[0075] According to another aspect, the step of injecting the second
mobilizing fluid
into the reservoir includes injecting the second mobilizing fluid into the
reservoir at a
pressure that is in a range of about 50% to about 80% of a lithostatic
pressure of the
reservoir.
[0076] These and other features and advantages of the present application
will
become apparent from the following detailed description taken together with
the
accompanying drawings. However, it should be understood that the detailed
description
and the specific examples, while indicating preferred embodiments of the
application, are
given by way of illustration only, since various changes and modifications
within the spirit
and scope of the application will become apparent to those skilled in the art
from this
detailed description.
Brief Description of the Drawings
[0077] For a better understanding of the various embodiments described
herein,
and to show more clearly how these various embodiments may be carried into
effect,
reference will be made, by way of example, to the accompanying drawings which
show
at least one example embodiment, and which are now described. The drawings are
not
intended to limit the scope of the teachings described herein.
[0078] FIG. 1A is a schematic cross sectional view of a underground
reservoir, a
vertical wellbore and a horizontal wellbore showing an example of dispersion
of solvent
and steam from along the horizontal wellbore after integrating solvent-based
injection with
cyclic steam stimulation processes;
[0079] FIG. 1B is a schematic cross sectional view of a underground
reservoir,
vertical wellbore and a horizontal wellbore showing an example of dispersion
of solvent
and steam from along the horizontal wellbore during a cyclic process;
[0080] FIG. 1C is a schematic cross sectional view of a underground
reservoir,
vertical wellbore and a horizontal wellbore showing an example of dispersion
of solvent
and steam from along the horizontal wellbore during a cyclic process;
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[0081] FIG. 1D is a schematic cross sectional view of a underground
reservoir,
vertical wellbore and a horizontal wellbore showing an example of dispersion
of solvent
and steam from along the horizontal wellbore during a cyclic process;
[0082] FIG. 2 is a block diagram of a method of recovering bitumen from an
underground reservoir, according to one embodiment;
[0083] FIG. 3 is a block diagram of a method of recovering bitumen from an
underground reservoir, according to another embodiment;
[0084] FIG. 4 is a block diagram of a method of recovering bitumen from an
underground reservoir, according to another embodiment;
[0085] FIG. 5 is a block diagram of a method of recovering bitumen from an
underground reservoir, according to another embodiment;
[0086] FIG. 6 is a block diagram of a method of recovering bitumen from an
underground reservoir, according to another embodiment; and
[0087] FIG. 7 is a graph comparing reservoir pressure over time for two
extraction
techniques: 1) seven cycles of CSS, and 2) four cycles of CSS followed by
three cycles
of CSP.
[0088] The skilled person in the art will understand that the drawings,
further
described below, are for illustration purposes only. The drawings are not
intended to limit
the scope of the applicant's teachings in any way. Also, it will be
appreciated that for
simplicity and clarity of illustration, elements shown in the figures have not
necessarily
been drawn to scale. For example, the dimensions of some of the elements may
be
exaggerated relative to other elements for clarity. Further aspects and
features of the
example embodiments described herein will appear from the following
description taken
together with the accompanying drawings.
Detailed Description
[0089] To promote an understanding of the principles of the disclosure,
reference
will now be made to the features illustrated in the drawings and no limitation
of the scope
of the disclosure is hereby intended. Any alterations and further
modifications, and any
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further applications of the principles of the disclosure as described herein
are
contemplated as would normally occur to one skilled in the art to which the
disclosure
relates. For the sake of clarity, some features not relevant to the present
disclosure may
not be shown in the drawings.
[0090] At the outset, for ease of reference, certain terms used in this
application
and their meanings as used in this context are set forth. To the extent a term
used herein
is not defined below, it should be given the broadest definition persons in
the pertinent art
have given that term as reflected in at least one printed publication or
issued patent.
Further, the present techniques are not limited by the usage of the terms
shown below,
as all equivalents, synonyms, new developments, and terms or techniques that
serve the
same or a similar purpose are considered to be within the scope of the present
claims.
[0091] As one of ordinary skill would appreciate, different persons may
refer to the
same feature or component by different names. This document does not intend to
distinguish between components or features that differ in name only. In the
following
description and in the claims, the terms "including" and "comprising" are used
in an open-
ended fashion, and thus, should be interpreted to mean "including, but not
limited to."
[0092] A "hydrocarbon" is an organic compound that primarily includes the
elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or
any
number of other elements may be present in small amounts. Hydrocarbons
generally
refer to components found in heavy oil or in oil sands. Hydrocarbon compounds
may be
aliphatic or aromatic, and may be straight chained, branched, or partially or
fully cyclic.
[0093] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a
range
from 1 to 9.
[0094] "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending
upon the degree of loss of more volatile components. It can vary from a very
viscous,
tar-like, semi-solid material to solid forms. The hydrocarbon types found in
bitumen can
include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen
might be
composed of:
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- 19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % to
30 wt. A)
or higher);
- 19 wt. % asphaltenes (which can range from 5 wt. % to 30 wt. % or
higher);
- 30 wt. % aromatics (which can range from 15 wt. % to 50 wt. % or higher);
- 32 wt. % resins (which can range from 15 wt. % to 50 wt. % or higher);
and
- some amount of sulfur (which can range in excess of 7 wt. %), based on
the total
bitumen weight.
[00951 In addition, bitumen can contain some water and nitrogen compounds
ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The percentage of
the
hydrocarbon found in bitumen can vary. The term "heavy oil" includes bitumen
as well as
lighter materials that may be found in a sand or carbonate reservoir.
[0096] "Heavy oil" includes oils which are classified by the American
Petroleum
Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term
"heavy oil" includes
bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or
more, 10,000
cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy
oil has an
API gravity between 22.3 API (density of 920 kilograms per meter cubed
(kg/m3) or 0.920
grams per centimeter cubed (g/cm3)) and 10.00 API (density of 1,000 kg/m3 or 1
g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.00 API
(density greater
than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil
sand or
bituminous sand, which is a combination of clay, sand, water and bitumen.
[0097] The term "viscous oil" as used herein means a hydrocarbon, or
mixture of
hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
at initial
reservoir conditions. Viscous oil includes oils generally defined as "heavy
oil" or
"bitumen." Bitumen is classified as an extra heavy oil, with an API gravity of
about 10 or
less, referring to its gravity as measured in degrees on the API Scale. Heavy
oil has an
API gravity in the range of about 22.3 to about 100. The terms viscous oil,
heavy oil, and
bitumen are used interchangeably herein since they may be extracted using
similar
processes.
[0098] In-situ is a Latin phrase for "in the place" and, in the context of
hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For
example,
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in-situ temperature means the temperature within the reservoir. In another
usage, an in-
situ oil recovery technique is one that recovers oil from a reservoir within
the earth.
[0099] The term "subterranean formation" refers to the material existing
below the
Earth's surface. The subterranean formation may comprise a range of
components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well
as the oil
and/or gas that is extracted. The subterranean formation may be a subterranean
body of
rock that is distinct and continuous. The terms "reservoir" and "formation"
may be used
interchangeably.
[0100] The term "wellbore" as used herein means a hole in the subsurface
made
by drilling or inserting a conduit into the subsurface. A wellbore may have a
substantially
circular cross section or any other cross-sectional shape. The term "well,"
when referring
to an opening in the formation, may be used interchangeably with the term
"wellbore."
[0101] The term "cyclic process" refers to an oil recovery technique in
which the
injection of a viscosity reducing agent into a wellbore to stimulate
displacement of the oil
alternates with oil production from the same wellbore and the injection-
production process
is repeated at least once. Cyclic processes for heavy oil recovery may include
a cyclic
steam stimulation (CSS) process, a liquid addition to steam for enhancing
recovery
(LASER) process, a cyclic solvent process (CSP), or any combination thereof.
[0102] The term "continuous process" as used herein refers to an oil
recovery
technique in which the injection of a viscosity reducing agent occurs in an
injector wellbore
to stimulate displacement of the oil alternatives with oil production
occurring in a separate
producer wellbore. The injector wellbore continuously injects the viscosity
reducing agent
into the reservoir and the producer wellbore continuously produces oil.
Continuous
processes for heavy oil recovery may include steam-assisted gravity drainage
(SAGD)
process, solvent-assisted-steam-assisted gravity drainage (SA-SAGD) process,
heated
solvent vapor-assisted petroleum extraction (H-VAPEX) process, solvent
flooding
process, or any combination thereof.
[0103] The term "forecast injection volume" as used herein means an
anticipated
or expected volume of a fluid to be injected into the reservoir.
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[0104] The term "lithostatic fracture pressure" as used herein means a
pressure at
which the rock above the reservoir (overburden) fractures. The lithostatic
fracture
pressure is the relationship between depth and increasing stress required to
fracture/fail
rock. The deeper a well, the higher the stress required to fail rock.
[0105] The articles "the," "a" and "an" are not necessarily limited to
mean only one,
but rather are inclusive and open ended to include, optionally, multiple such
elements.
[0106] As used herein, the terms "approximately," "about,"
"substantially," and
similar terms are intended to have a broad meaning in harmony with the common
and
accepted usage by those of ordinary skill in the art to which the subject
matter of this
disclosure pertains. It should be understood by those of skill in the art who
review this
disclosure that these terms are intended to allow a description of certain
features
described and claimed without restricting the scope of these features to the
precise
numeral ranges provided. Accordingly, these terms should be interpreted as
indicating
that insubstantial or inconsequential modifications or alterations of the
subject matter
described and are considered to be within the scope of the disclosure.
[0107] "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, to at
least one, optionally
including more than one, A, with no B present (and optionally including
entities other than
B); to at least one, optionally including more than one, B, with no A present
(and optionally
including entities other than A); 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
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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.
[0108] Where two or more ranges are used, such as but not limited to 1 to
5 or 2
to 4, any number between or inclusive of these ranges is implied.
[0109] As used herein, the phrases "for example," "as an example," and/or
simply
the terms "example" or "exemplary," when used with reference to one or more
components, features, details, structures, methods and/or figures according to
the
present disclosure, are intended to convey that the described component,
feature, detail,
structure, method and/or figure is an illustrative, non-exclusive example of
components,
features, details, structures, methods and/or figures according to the present
disclosure.
Thus, the described component, feature, detail, structure, method and/or
figure is not
intended to be limiting, required, or exclusive/exhaustive; and other
components,
features, details, structures, methods and/or figures, including structurally
and/or
functionally similar and/or equivalent components, features, details,
structures, methods
and/or figures, are also within the scope of the present disclosure. Any
embodiment or
aspect described herein as "exemplary" is not to be construed as preferred or
advantageous over other embodiments.
[0110] In spite of the technologies that have been developed, there
remains a need
in the field for methods of enhancing the recovery of bitumen.
[0111] Various approaches of enhancing solvent-based extraction processes
with
the addition of steam are described herein. The proposed approaches involve
utilizing
and integrating different steam processes and recovery mechanisms at different
stages
of solvent-based extraction processes to enhance the bitumen recovery from a
reservoir.
[0112] Referring now to Figures 1A to 1D, illustrated therein are
schematic cross
sectional views of an underground reservoir, a vertical wellbore and a
horizontal wellbore
showing an example of dispersion of solvent and steam along the horizontal
wellbore
after integrating one or more cyclic solvent processes (CSPs) with one or more
cyclic
steam stimulation processes (CSSs).
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[0113] For instance, FIG. 1A shows a schematic cross sectional view of an
underground reservoir 100, a vertical wellbore 102 and a horizontal wellbore
104 showing
an example of dispersion of solvent and steam along the horizontal wellbore
after
performing each a first cycle using a cyclic solvent process (CSP) 106,
followed by a
second cycle using a CSP 108, followed by a third cycle using a cyclic steam
stimulation
process (CSS) 110.
[0114] FIG. 1B is a schematic cross sectional view of an underground
reservoir
100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example
of
dispersion of solvent and steam along the horizontal wellbore after performing
each a first
cycle of a CSS 112, followed by a second cycle using a CSP 114, followed by a
third
cycle using a CSP 116, followed by a fourth cycle using a CSS 118.
[0115] FIG. 1C is a schematic cross sectional view of an underground
reservoir
100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example
of
dispersion of solvent and steam along the horizontal wellbore after performing
each a first
cycle of a CSP 120, followed by a second cycle of a CSS 122, followed by a
third cycle
of a CSS 124, followed by a fourth cycle using a CSP 126.
[0116] FIG. 1D is a schematic cross sectional view of an underground
reservoir
100, a vertical wellbore 102 and a horizontal wellbore 104 showing an example
of
dispersion of solvent and steam along the horizontal wellbore after each a
first cycle of a
CSS 128, followed by a second cycle using a CSS 130, followed by a third cycle
using
CSP 132, followed by a fourth cycle using a CSP 134.
[0117] In the aforementioned CSPs, solvents may be used as a mobilizing
fluid to
enhance the extraction of petroleum products from the reservoir. Herein, the
term "second
mobilizing fluid" generally refers to a solvent for enhancing the extraction
of petroleum
products from the reservoir. The solvent may be a light hydrocarbon, a mixture
of light
hydrocarbons or dimethyl ether. In other embodiments, the solvent may be a C2-
C7
alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant
condensate
comprising alkanes, naphthenes, and aromatics.
[0118] In other embodiments, the solvent may be a light, but condensable,
hydrocarbon or mixture of hydrocarbons comprising ethane, propane, butane, or
pentane.
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The solvent may comprise at least one of ethane, propane, butane, pentane, and
carbon
dioxide. The solvent may comprise greater than 50 mol% C2-05 hydrocarbons on a
mass
basis. The solvent may be greater than 50 mor/0 propane, optionally with
diluent when it
is desirable to adjust the properties of the injectant to improve performance.
[0119] Additional injectants may include CO2, natural gas, C5+
hydrocarbons,
ketones, and alcohols. Non-solvent injectants that are co-injected with the
solvent may
include steam, non-condensable gas, or hydrate inhibitors. The solvent
composition may
comprise at least one of diesel, viscous oil, natural gas, bitumen, diluent,
C5+
hydrocarbons, ketones, alcohols, non-condensable gas, water, biodegradable
solid
particles, salt, water soluble solid particles, and solvent soluble solid
particles.
[0120] To reach a desired injection pressure of the solvent composition, a
viscosifier may be used in conjunction with the solvent. The viscosifier may
be useful in
adjusting solvent viscosity to reach desired injection pressures at available
pump rates.
The viscosifier may include diesel, viscous oil, bitumen, and/or diluent. The
viscosifier
may be in the liquid, gas, or solid phase. The viscosifier may be soluble in
either one of
the components of the injected solvent and water. The viscosifier may
transition to the
liquid phase in the reservoir before or during production. In the liquid
phase, the
viscosifiers are less likely to increase the viscosity of the produced fluids
and/or decrease
the effective permeability of the formation to the produced fluids.
[0121] The solvent composition may comprise (i) a polar component, the
polar
component being a compound comprising a non-terminal carbonyl group; and (ii)
a non-
polar component, the non-polar component being a substantially aliphatic
substantially
non-halogenated alkane. The solvent composition may have a Hansen hydrogen
bonding parameter of 0.3 to 1.7 (or 0.7 to 1.4). The solvent composition may
have a
volume ratio of the polar component to non-polar component of 10:90 to 50:50
(or 10:90
to 24:76, 20:80 to 40:60, 25:75 to 35:65, or 29:71 to 31:69). The polar
component may
be, for instance, a ketone or acetone. The non-polar component may be, for
instance, a
C2-C7 alkane, a C2-C7 n-alkane, an n-pentane, an n-heptane, or a gas plant
condensate
comprising alkanes, naphthenes, and aromatics. For further details and
explanation of
the Hansen Solubility Parameter System see, for example, Hansen, C. M. and
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Beerbower, Kirk-Othmer, Encyclopedia of Chemical Technology, (Suppl. Vol. 2nd
Ed),
1971, pp 889-910 and "Hansen Solubility Parameters A User's Handbook" by
Charles
Hansen, CRC Press, 1999.
[0122] The solvent composition may comprise (i) an ether with 2 to 8 carbon
atoms;
and (ii) a non-polar hydrocarbon with 2 to 30 carbon atoms. Ether may have 2
to 8 carbon
atoms. Ether may be di-methyl ether, methyl ethyl ether, di-ethyl ether,
methyl iso-propyl
ether, methyl propyl ether, di-isopropyl ether, di-propyl ether, methyl iso-
butyl ether,
methyl butyl ether, ethyl iso-butyl ether, ethyl butyl ether, iso-propyl butyl
ether, propyl
butyl ether, di-isobutyl ether, or di-butyl ether. Ether may be di-methyl
ether. The non-
polar hydrocarbon may a C2-C30 alkane. The non-polar hydrocarbon may be a C2-
05
alkane. The non-polar hydrocarbon may be propane. The ether may be di-methyl
ether
and the hydrocarbon may be propane. The volume ratio of ether to non-polar
hydrocarbon may be 10:90 to 90:10; 20:80 to 70:30; or 22.5:77.5 to 50:50.
[0123] The solvent composition may comprise at least 5 mol % of a high-
aromatics
component (based upon total moles of the solvent composition) comprising at
least 60
wt. % aromatics (based upon total mass of the high-aromatics component). One
suitable
and inexpensive high-aromatics component is gas oil from a catalytic cracker
of a
hydrocarbon refining process, also known as a light catalytic gas oil (LCGO).
[0124] In some embodiments, different steam processes and recovery
mechanisms can be integrated with solvent-based extraction processes by
initiating the
steam processes prior to a first cycle of a solvent-based extraction process.
[0125] Referring now to FIG. 2, illustrated therein is a method 200 of
recovering
bitumen from an underground reservoir penetrated by at least one well. The
method 200
includes at a step 202, injecting a first mobilizing fluid into the reservoir.
Generally, herein
the term "first mobilizing fluid" refers to a steam-dominated fluid, where
"steam-
dominated" refers to a fluid that is primarily (e.g. greater than 50% by mass)
steam.
Herein, "steam" refers to water in vapor form with a quality between 0% (i.e.
saturated
steam) and 100% (i.e. dry steam). In some embodiments, the steam of the
methods
described herein has a quality of about 70 /o.The first mobilizing fluid may
also be pure
steam or water having a temperature above about 25 C. In some embodiments,
the first
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mobilizing fluid may have a temperature of about 200 C. In other embodiments,
the first
mobilizing fluid may have a temperature of about 325 C.
[0126] The method 200 also includes, at a step 204, shutting in the first
mobilizing
fluid that is in the reservoir to lower a viscosity of at least a portion of
the bitumen in the
reservoir. Shutting in the first mobilizing fluid that is in the reservoir
generally includes
stopping injecting the first mobilizing fluid into the reservoir and sealing
the reservoir. For
instance, stopping injecting the first mobilizing fluid into the reservoir may
include shutting
a steam valve at a steam injection header on the pad, for CSP it would be
turning off
injection pumps in the injection system. In another example, after turning off
injection, the
valves on the wellhead of injection/production well would be closed. This
would be on the
production tubing and casing system.
[0127] At step 206, the first mobilizing fluid in the reservoir is held in
the reservoir
for a period of time. For example, the period of time may be in a range of
about 4 hours
to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0128] At step 208, bitumen of a lowered viscosity (e.g. relative to
bitumen that
remains in the reservoir) is recovered from the reservoir.
[0129] It should be understood that in some embodiments of the method 200,
the
steps 202-208 are repeated one or more times prior to proceeding to step 210.
[0130] At step 210, at least one casing integrity issue in the wellbore is
detected.
Herein, casing integrity issues generally include any physical indication that
damages or
threatens to damage the wellbore casing. In some instances, the casing
integrity issues
may be detected by a person performing a casing integrity check of the
wellbore (e.g. on
a scheduled basis) with quantitative measure of ovalities in the casing and
shift used to
classify damage and allowable wellbore service. Herein, the term "ovality"
refers to a
measure of mechanical damage that can be used to interpret strain, offset, and
deformation shape within a wellbore. Ovality is specifically defined as a
difference
between a shape of an inner wellbore and an ideal circular shape (e.g. same
inner
diameter throughout wellbore). Ovality can also be considered to be a
difference between
a maximum inner diameter and a minimum inner diameter of a wellbore. Ovality
is
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typically measured in millimeters with higher ovality measurements (ovalities)
leading to
higher impairment classifications.
[0131] Generally, the integrity of a wellbore, or more specifically of the
casing of a
wellbore, has four components: detection, prevention, response and recover. In
detection,
monitoring systems (as described below) and/or casing integrity checks may be
performed to detect a casing integrity issue. In prevention, design of the
wellbore (e.g.
casing, threaded connection, materials, etc.), operating practices and shear
stress
management and well environmental control (H2S purge) are all parameters that
can
contribute to the prevention of casing integrity issues of a wellbore. In
response, well
control capability (e.g. well kill procedures) and casing repair (e.g. patch,
slim hole, and
other repair) are each common responses to casing integrity issues. Finally,
in recover,
regulatory compliance and improved well utility (e.g. producer only, injector
only, redeploy
well and re-drill) are all important considerations for recovering from well
integrity issues.
[0132] Some examples of casing integrity detection include, but are not
limited to,
differential flow pressure (DFP) issues. For example, DFP issues may arise
when a
wellbore is injecting with elevated pressure while steaming and experiences
sudden
increase in flow rate with a drop in instantaneous pressure. DFP issues may be
indicative
of a break in the casing. In some embodiments, the monitoring system described
herein
may be a DFP monitoring system. DFP monitoring systems may be used to identify
a
potential casing integrity issue during steam injection for CSS, for example.
During normal
steam injection, a steam manifold pressure and wellhead pressure increase or
remain
constant with steady to increasing steam injection rates. There is pressure
and rate
measurement on wells and manifold. If the injection rate increases and
wellhead and/or
manifold pressure declines it could be indicative of a casing integrity issue.
[0133] Casing integrity issues may vary in severity. For example, casing
integrity
issues may be higher consequence issues, such as, but not limited to a high
pressure
failure outside the target reservoir with fluids (e.g. steam, water, oil)
entering out of zone.
[0134] In other examples, casing integrity issues may be an inability to
steam well
at high pressure as casing integrity doesn't allow high pressure steam (i.e.
greater than
6 MPa bottom hole pressure).
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[0135] In other examples, casing integrity issues may be an inability to
steam well
at any pressure.
[0136] In other examples, casing integrity issues may be an inability to
steam or
produce from well.
[0137] In other examples, casing integrity issues may include well failure
and
inability to steam wells in immediate area (e.g. within one or greater well
spacing at 4 or
8 acre)
[0138] In some embodiments, the at least one casing integrity issue in the
wellbore
is detected by a monitoring system. For instance, in some embodiments, the
monitoring
system may be a passive seismic monitoring system. Passive seismic monitoring
systems generally include a dedicated monitoring well on a pad with geophones
installed
downhole (e.g. below the surface and within wellbore 102). Geophones convert
movement (e.g. of the ground) into voltage that can be recorded at a recording
station.
By dispersing a plurality of geophones downhole within the monitoring well,
the
geophones can triangulate movement of the ground to identify a well integrity
event
and/or a casing integrity issue within a neighboring wellbore. For instance, a
casing failure
can be identified by distinctive events with seismic signatures (p-waves & s-
waves). In
some embodiments, passive seismic monitoring systems can identify events
during
injection and soaking period for CSS wells.
[0139] In some embodiments, the monitoring system may be an N2 soak
monitoring system. N2 soak monitoring systems may be used to detect a casing
integrity
issue in a wellbore after injection of a mobilizing fluid into the wellbore
and before
production of bitumen from the wellbore. N2 soak monitoring systems utilize a
process
where N2 is injected down the casing of a wellbore and left to soak (i.e. for
a period of
time in a range of about 24 to 48 hours). The fluid level and pressure in
casing can be
monitored. Significant pressure changes for the shut-in well could indicate
casing integrity
issues.
[0140] In some embodiments, the monitoring system may be casing integrity
checks. Herein, the term "casing integrity checks" is used as a catch all
phrase for a suite
of tests. For instance, in one example of a casing integrity check, the tubing
and bottom-
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hole pump can be pulled out of the well for testing with concern about the
intermediate
casing and not the tubing. For example, in instances where the structural
integrity of an
intermediate casing of the wellbore is of concern, the tests may include a
pressure test
on the tubing and casing of a wellbore to see if the tubing and/or the casing
can hold
required pressures. The tests may also include running tools on a wire line
truck (e.g.
such as but not limited to a scraper / drift) to identify obstructions or
changes in well shape
(e.g. circular vs. oval) and depth of the obstruction that is located. This
test can include
other wire line tools such as but not limited to calipers that will provide
details of shape of
casing and areas of casing integrity issues. The tests can also include other
wire line tools
such as but not limited to a corrosion logging tool. This a tool that can
produce a corrosion
log report that measures corrosion in the casing (e.g. external and internal).
If the
thickness of the casing is below a predetermined threshold for the pressure,
then casing
integrity may be an issue. Examples of a corrosion logging tool may include
but are not
limited to Vertilog, DVERT, MVERT, and HVERT.
[0141] In some embodiments, the casing integrity issues may be found by
performing casing integrity checks on a scheduled basis with quantitative
measure of
ovalities and shift used to classify damage and allowable wellbore service.
[0142] At a step 212, in response to detecting the casing integrity issue
in the
wellbore, a second mobilizing fluid is injected through the wellbore into the
reservoir.
Injecting the second mobilizing fluid through the wellbore into the reservoir
can reduce a
pressure of the reservoir and reduce thermal cycling. Generally, the second
mobilizing
fluid includes a hydrocarbon solvent (as described above).
[0143] In some embodiments, the second mobilizing fluid differs from the
first
hydrocarbon fluid.
[0144] In some embodiments, detecting the casing integrity issue may occur
during
an injection step of a subsequent CSS. Here, in response to detecting the
casing integrity
issue and prior to injecting the second mobilizing fluid, injection of the
first mobilizing fluid
into the underground reservoir may be shut in and held for a period of time.
For example,
holding the first mobilizing fluid in the underground reservoir may be for a
period of time
in a range of about 24 to 48 hours. Shutting in and holding the first
mobilizing fluid in the
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underground reservoir may provide for performing diagnostic work to confirm
the casing
integrity issue in the wellbore. For instance, holding the first mobilizing
fluid in the reservoir
after detecting the casing integrity issue may include analyzing data
collected from the
wellbore and/or the reservoir prior to detecting the casing integrity issue to
confirm the
casing integrity issue and/or analyzing data collected from the wellbore
and/or the
reservoir after detecting the casing integrity issue to confirm the casing
integrity issue.
[0145] An effect of switching from the first mobilizing fluid (e.g. steam)
to the
second mobilizing fluid (e.g. solvent) (e.g. switching from a CSS to a CSP) is
reducing
the pressure of the underground reservoir. Switching to a CSP from a CSS may
therefore
help alleviate and/or mitigate issues with wellbores undergoing a CSS,
particularly in
CSSs that are mid to late life (e.g. after about 3 -4 cycles of CSS). For
instance, FIG. 7 is
a graph comparing reservoir pressure over time for two extraction techniques:
1) seven
cycles of CSS, and 2) four cycles of CSS followed by three cycles of CSP, at a
same
injection rate. This example shows that CSPs can significantly lower the
operating
pressure of an underground reservoir and thus help mitigate pump, fluid
excursion and/or
casing integrity issues associated with extracting bitumen from the
underground reservoir.
The decrease in pressure of the reservoir during a CSP may be due to one or
more of a
number of factors. For instance, generally, mobilizing fluids used in CSPs
have less
thermal energy than mobilizing fluids used in CSSs (e.g. solvent used in a CSP
may be
about 50 C with no phase change and steam used in a CSS may be about 300 C
with
a phase change to water). In another example, there is a sub-fracture pressure
requirement for CSP technology. In another example, solvents used in CSPs are
generally partially miscible in bitumen. Any one or more of these factors may
help in
lowering the underground reservoir pressure and limit casing integrity issues,
as well as,
an out of zone fluid excursion.
[0146] At step 214, the second mobilizing fluid is shut into the
reservoir. Shutting
in the second mobilizing fluid into the reservoir generally lowers the
viscosity of at least a
portion of the bitumen in the reservoir.
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[0147] At step 216, the second mobilizing fluid in the reservoir is held
in the
reservoir for a period of time. For example, the period of time may be in a
range of about
4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0148] At step 218, bitumen of lowered viscosity is recovered from the
reservoir.
[0149] In some embodiments of the method 200, step 202 of injecting the
first
mobilizing fluid through the wellbore into the reservoir, step 204 of shutting
in the first
mobilizing fluid that is in the reservoir to lower the viscosity of at least a
portion of the
bitumen in the reservoir, step 206 of holding the first mobilizing fluid in
the reservoir and
step 208 of recovering bitumen of lowered viscosity from the reservoir are all
part of a
CSS process for recovering bitumen from the underground reservoir.
[0150] In some embodiments of the method 200, step 212 of injecting the
second
mobilizing fluid through the wellbore into the reservoir, step 214 of shutting
in the second
mobilizing fluid that is in the reservoir, step 216 of holding the second
mobilizing fluid in
the reservoir and step 218 of recovering bitumen of lowered viscosity from the
reservoir
are part of a CSP for recovering bitumen from the underground reservoir.
[0151] In another aspect, a method 300 of recovering bitumen from an
underground reservoir penetrated by at least one wellbore is also described
herein. This
method includes, at a step 302, injecting a first mobilizing fluid through the
wellbore into
the reservoir. As discussed above with reference to the method 200, the first
mobilizing
fluid generally includes steam.
[0152] At step 304, the first mobilizing fluid is shut into the reservoir
to lower
viscosity of at least a portion of the bitumen in the reservoir.
[0153] At step 306, the first mobilizing fluid in the reservoir is held in
the reservoir
for a period of time. For example, the period of time may be in a range of
about 4 hours
to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0154] At a step 308, bitumen of lowered viscosity is recovered from the
reservoir.
[0155] At a step 310, at least one fluid excursion issue in the wellbore
is detected.
Herein, "fluid excursion issue" generally refers to fluid injected into the
production interval
that leaves the target interval. The injected fluid can be determined to come
from a
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specific well. It is the fluid already injected from the well leaving a
geologic zone that is of
concern. Fluid already injected from the well leaving a geologic zone implies
fluid has left
the target injection and production reservoir interval and migrated through an
isolating
geologic feature (i.e. normally non-permeable shale layer) to another
zone/interval. The
cause of fluid excursion can vary and include but is not limited to: casing
failure, vertical
fracture, fault in isolating geologic feature (shale), and/or flow outside
casing.
[0156] In some embodiments, fluid excursion issues can be found using
monitoring
wells. In some embodiments, detecting the at least one fluid excursion issue
at step 310
is by monitoring a pressure of the reservoir via one or more observation
wellbores offset
from a production pad including the wellbore and detecting an increase in the
pressure of
the reservoir.
[0157] In some embodiments, detecting the at least one fluid excursion
issue at
step 310 is by analyzing injection and production pressure profiles of pad or
pressure
profiles of offset observation wellbores. For instance, sudden changes (or
responses) in
pressure over time may be referred to as "sharp" responses and may be
indicative of fluid
excursion. Sharp responses may be typified by a quick increase in dP/dt to a
peak
followed by an equally quick drop off. For instance, a typical range for a
"quick" increase
may be an increase in pressure over time in a range of about 50 to about 100
kPa/day
followed by a decrease in a range of about 50 to about 100 kPa/day over a
period of
about 12 hours. Sharp response such as those described herein may be self-
correcting
and can generally be identified through DFPs, seismic activity or response
triangulation.
[0158] "Dull" responses may also be indicative of fluid excursion. Dull
responses
are typified by a slow increase in baseline changes in pressure over time. For
instance,
dull responses generally fall in the range of 0-50 kPa/day. Dull responses are
generally
not self-correcting. This can be conceptually visualized as a "leaker hose".
Dull responses
may be identified through seismic activity or response triangulation and are
not generally
associated with DFPs.
[0159] In some embodiments, detecting the at least one fluid excursion
issue may
occur during an injection step of the CSS. Here, in response to detecting the
at least one
fluid excursion issue and prior to injecting the second mobilizing fluid, the
first mobilizing
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fluid may be shut in and held in the reservoir. Shutting in and holding the
first mobilizing
fluid in the reservoir may be for a period of time in a range of about 24 to
48 hours.
Shutting in and holding the first mobilizing fluid in the reservoir may
provide for performing
diagnostic work to confirm the at least one fluid excursion issue in the
wellbore. Shutting
in and holding the first mobilizing fluid in the reservoir may provide for
analyzing data
collected from the wellbore and/or the underground reservoir prior to
detecting the fluid
excursion issue to confirm the fluid excursion issue. Shutting in and holding
the first
mobilizing fluid in the reservoir may provide for analyzing data collected
from the wellbore
and/or the underground reservoir after detecting the fluid excursion issue to
confirm the
fluid excursion issue. In some embodiments, detecting the fluid excursion
issue may
occur during the shutting in and/or the holding step of a subsequent CSS.
[0160] At a step 312, in response to detecting the at least one fluid
excursion issue
in the wellbore, a second mobilizing fluid is injected into the reservoir. As
noted above
with reference to method 200, the second mobilizing fluid includes a
hydrocarbon solvent.
[0161] Generally, during injection of the second mobilizing fluid, the
wellbore has
a lower bottom-hole pressure relative to injection of the first mobilizing
fluid due to the
second mobilizing fluid having, for example, a lower thermal energy. Further,
the sub-
fracture pressure nature of CSP and partial miscibility of the second
mobilizing fluid in
bitumen also may contribute to the pressure of the underground reservoir
decreasing
during CSPs relative to CSSs.
[0162] At step 314, the second mobilizing fluid is shut into the reservoir
to lower a
viscosity of at least a portion of the bitumen in the reservoir.
[0163] At step 316, the second mobilizing fluid in the reservoir is held
in the
reservoir for a period of time. For example, the period of time may be in a
range of about
4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0164] At a step 318, bitumen of lowered viscosity is recovered from the
reservoir.
[0165] In some embodiments, step 302 of injecting the first mobilizing
fluid through
the wellbore into the reservoir, step 304 of shutting in the first mobilizing
fluid that is in the
reservoir to lower the viscosity of at least a portion of the bitumen in the
reservoir, step
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306 of holding the first mobilizing fluid in the reservoir and step 308 of
recovering bitumen
of lowered viscosity from the reservoir are part of a CSS process for
recovering bitumen
from the underground reservoir.
[0166] In some embodiments, step 312 of injecting the second mobilizing
fluid
through the wellbore into the reservoir, step 314 of shutting in the second
mobilizing fluid
that is in the reservoir, step 316 of holding the second mobilizing fluid in
the reservoir and
step 318 of recovering bitumen of lowered viscosity from the reservoir are
part of a CSP
for recovering bitumen from the underground reservoir.
[0167] In another aspect, a method 400 of recovering bitumen from an
underground reservoir penetrated by at least one well is also described
herein. Method
400 includes at a step 402, injecting a first mobilizing fluid into the
reservoir, the first
mobilizing fluid including steam;
[0168] At step 404, method 400 includes shutting in the first mobilizing
fluid that is
in the reservoir to lower viscosity of at least a portion of the bitumen in
the reservoir.
[0169] At step 406, the first mobilizing fluid in the reservoir is held in
the reservoir
for a period of time. For example, the period of time may be in a range of
about 4 hours
to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0170] At a step 408, method 400 includes recovering bitumen of lowered
viscosity
from the reservoir.
[0171] At a step 410, method 400 includes detecting a pump issue in the
wellbore.
Detecting pump issues in the at least one well may include detecting a low
fillage rate of
a pump of the well. For instance, an exemplary low fillage rate may be in a
range of about
25% or lower. Detecting pump issues in the at least one well may also include
detecting
flashing of a fluid within a pump of the well and/or detecting a gaseous fluid
in production
tubing of the casing.
[0172] Pump issues may be caused by operating conditions of the produced
fluid
being in a lower pressure and high temperature regime, which, for example, may
result
in flashing of liquid water to vapor in the underground reservoir or within
the pump itself.
Generally, the second mobilizing fluid being injected into the underground
reservoir will
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have a different liquid/vapor profile when compared to the first mobilizing
fluid being
injected into the underground reservoir. Specifically, the second mobilizing
fluid can be
injected at a lower temperature than the first mobilizing fluid, thereby
reducing the
pressure of the underground reservoir. The second mobilizing fluid, bitumen,
and water
in the reservoir may therefore be at a lower temperature during the CSP when
compared
to the CSS, and produced fluids can move out of liquid/vapor window and into
the liquid
only window. Operating in the liquid only window may increase pump efficiency,
increase
fillage and improve pump run time, prevent flashing in the pump, and
potentially delay
pump failure.
[0173] In some embodiments, detecting the pump issue may occur during an
injection step of the CSS. Here, in response to detecting the pump issue and
prior to
injecting the second mobilizing fluid, injection of the first mobilizing fluid
into the
underground reservoir may be shut in and held. Shutting in and holding the
first mobilizing
fluid in the reservoir may be for a period of time in a range of about 24 to
48 hours.
Shutting in and holding the first mobilizing fluid in the reservoir may
provide for performing
diagnostic work to confirm the pump issue in the wellbore. Shutting in and
holding the first
mobilizing fluid in the reservoir may provide for analyzing data collected
from the wellbore
and/or the underground reservoir prior to detecting the pump issue to confirm
the pump
issue. Shutting in and holding the first mobilizing fluid in the reservoir may
provide for
analyzing data collected from the wellbore and/or the underground reservoir
after
detecting the pump issue to confirm the pump issue. In some embodiments,
detecting the
pump issue may occur during the shutting in and/or the holding step of a
subsequent
CSS.
[0174] At step 412, a second mobilizing fluid is injected into the
reservoir. As noted
above, the second mobilizing fluid includes a hydrocarbon solvent. Step 412 of
injecting
a second mobilizing fluid into the reservoir is initiated upon detecting a
pump issue in the
at least one well.
[0175] At step 414, method 400 includes shutting in the second mobilizing
fluid that
is in the reservoir to lower viscosity of at least a portion of the bitumen in
the reservoir.
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[0176] At step 416, the second mobilizing fluid in the reservoir is held
in the
reservoir for a period of time. For example, the period of time may be in a
range of about
4 hours to about 48 hours, or in a range of about 24 hours to about 48 hours.
[0177] At step 418, method 400 includes recovering bitumen of lowered
viscosity
from the reservoir.
[0178] In some embodiments, step 402 of injecting the first mobilizing
fluid through
the wellbore into the reservoir, step 404 of shutting in the first mobilizing
fluid that is in the
reservoir to lower the viscosity of at least a portion of the bitumen in the
reservoir, step
406 of holding the first mobilizing fluid in the reservoir, and step 408 of
recovering bitumen
of lowered viscosity from the reservoir are part of a CSS process for
recovering bitumen
from the underground reservoir.
[0179] In some embodiments, step 412 of injecting the second mobilizing
fluid
through the wellbore into the reservoir, step 414 of shutting in the second
mobilizing fluid
that is in the reservoir, step 416 of holding the second mobilizing fluid in
the reservoir and
step 418 of recovering bitumen of lowered viscosity from the reservoir are
part of a CSP
for recovering bitumen from the underground reservoir.
[0180] According to another aspect, a method 500 of recovering bitumen
from an
underground reservoir penetrated by at least one well is described herein.
Method 500
includes at a step 502, operating a first cyclic solvent process for
recovering bitumen from
an underground reservoir in the at least one well. The first cyclic solvent
process includes,
at a step 504, injecting a first mobilizing fluid into the reservoir. As noted
above, the first
mobilizing fluid includes a hydrocarbon solvent.
[0181] Step 502 of operating the first cyclic solvent process also.
includes, at a step
506, shutting in the first mobilizing fluid that is in the reservoir to lower
viscosity of at least
a portion of the bitumen in the reservoir.
[0182] Step 502 of operating the first cyclic solvent process also
includes, at a step
508, recovering bitumen of lowered viscosity from the reservoir.
[0183] At a step 510, during a subsequent cyclic solvent process, when a
pressure
of the underground reservoir is less than 50% of a lithostatic pressure during
the step of
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injecting the first mobilizing fluid into the reservoir, the at least one well
is converted to a
producer well of a solvent flooding process, where one or more neighboring
wells are
injector wells and bitumen from the underground reservoir is produced from the
converted
producer well.
[0184] According to another aspect, a method 600 of recovering bitumen from
an
underground reservoir penetrated by at least one well is disclosed herein.
Method 600
includes at a step 602 operating a cyclic solvent process for recovering
bitumen from an
underground reservoir in the at least one well. The cyclic solvent process
includes, at a
step 604, injecting a first mobilizing fluid into the reservoir. The first
mobilizing fluid
includes a hydrocarbon solvent.
[0185] Step 602 of operating a cyclic solvent process for recovering
bitumen from
an underground reservoir in the at least one well also includes, at a step
606, shutting in
the first mobilizing fluid that is in the reservoir to lower viscosity of at
least a portion of the
bitumen in the reservoir.
[0186] Step 602 of operating a cyclic solvent process for recovering
bitumen from
an underground reservoir in the at least one well also includes, at a step
608, recovering
bitumen of lowered viscosity from the reservoir.
[0187] At a step 610, an infill well is provided in an unswept region of
the
underground reservoir formed between the at least one well and a neighboring
well
operating a cyclic solvent process.
[0188] At a step 612, a cyclic process is operated in the infill well for
recovering
bitumen from the underground reservoir. The cyclic process operated at step
612
includes, at a step 614, injecting a second mobilizing fluid into the
reservoir. The second
mobilizing fluid includes steam.
[0189] The cyclic process operated at step 612 also includes, at a step
616,
shutting in the second mobilizing fluid that is in the reservoir to lower
viscosity of at least
a portion of the bitumen in the reservoir and, at a step 618, recovering
bitumen of lowered
viscosity from the reservoir.
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[0190] In some embodiments, the step of injecting the second mobilizing
fluid into
the reservoir includes injecting the second mobilizing fluid into the
reservoir at a pressure
that is greater than 50% of a lithostatic pressure of the reservoir, within a
range of about
50% to about 80% of a lithostatic pressure of the reservoir, or greater than
80% of a
lithostatic pressure of the reservoir.
[0191] FIG. 7 is a graph comparing reservoir pressure over time for two
extraction
techniques: 1) seven cycles of CSS, and 2) four cycles of CSS followed by
three cycles
of CSP, each having the same injection rate. This example shows that CSPs can
significantly lower the operating pressure of an underground reservoir and
thus help
mitigate pump, fluid excursion and/or casing integrity issues associated with
extracting
bitumen from the underground reservoir.
[0192] While the applicant's teachings described herein are in conjunction
with
various embodiments for illustrative purposes, it is not intended that the
applicant's
teachings be limited to such embodiments as the embodiments described herein
are
intended to be examples. On the contrary, the applicant's teachings described
and
illustrated herein encompass various alternatives, modifications, and
equivalents, without
departing from the embodiments described herein, the general scope of which is
defined
in the appended claims.
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