Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
OPTIMIZATION OF CYCLIC SOLVENT PROCESSES
Technical Field
[0001] The present disclosure relates generally to methods of recovering
hydrocarbons, and more specifically to methods of optimizing cyclic solvent
processes
for recovering bitumen and heavy oil 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] A cyclic solvent process (CSP) is an in-situ bitumen and heavy oil
recovery
process that consists of alternating cycles of solvent injection and
solvent/bitumen mixture
production through the same horizontal well. The solvent, injected in the
liquid state,
fingers into the bitumen and mixes with it, reducing its viscosity to provide
for the bitumen
to be extracted from the reservoir.
[0004] Generally, in CSPs, cycles grow progressively in length and volume
as the
reservoir becomes depleted. In later cycles, larger volumes of solvent must be
injected to
fill the voidage created by bitumen and water production and to re-pressurize
the
formation.
[0005] After production begins, the early-stage produced fluid is the
uncontacted,
mostly-pure solvent. Generally, the produced fluid is sent through a
separation facility
where the solvent is separated from the bitumen using single or multi-stage
separator
processes. However, separating the solvent from the small amount of bitumen in
the
produced fluid is generally not a very efficient process, and thus it
drastically increases
energy use in the form of compression and pumping costs for the facility and
requires
larger separator equipment sizes to accommodate the larger throughput.
[0006] Accordingly, there is a need for improved methods optimizing
solvent use
in CSPs.
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Summary
[0007] The present disclosure provides methods of recovering bitumen from
a
reservoir. In some embodiments, the methods include injecting a first
mobilizing fluid into
the underground reservoir through a first well, the first mobilizing fluid
having a pressure
that is above a liquid/vapor phase change pressure of the first mobilizing
fluid; producing
a first produced fluid from the underground reservoir through the first well,
the first
produced fluid including bitumen and at least a portion of the first
mobilizing fluid injected
into the underground reservoir; mixing at least a portion of the first
produced fluid with a
make-up fluid to form a second mobilizing fluid; injecting the second
mobilizing fluid into
the underground reservoir through a second well, the second mobilizing fluid
having a
pressure that is above a liquid/vapor phase change pressure of the second
mobilizing
fluid; and producing a second produced fluid from the underground reservoir
through the
second well, the second produced fluid including bitumen and at least a
portion of the
second mobilizing fluid injected into the underground reservoir.
[0008] In some embodiments, the first mobilizing fluid has a temperature
in a range
of about 10 C to about 90 C.
[0009] In some embodiments, the make-up fluid has a temperature in a
range of
about 10 C to about 90 C.
[0010] In some embodiments, the first mobilizing fluid comprises propane.
[0011] In some embodiments, the first mobilizing fluid is propane.
[0012] In some embodiments, the first mobilizing fluid comprises propane
and
dimethyl ether (DME).
[0013] In some embodiments, the first mobilizing fluid comprises natural
gas liquid
(NGL).
[0014] In some embodiments, the first mobilizing fluid comprises
liquefied
petroleum gas (LPG).
[0015] In some embodiments, the first mobilizing fluid comprises light
catalytic gas
oil.
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,
[0016] In some embodiments, the first mobilizing fluid comprises
propane and a
non-condensable gas (NCG) such as Cl, CO2, flue gas, or a combination of
thereof.
[0017] In some embodiments, the make-up fluid comprises DME.
[0018] In some embodiments, the make-up fluid is DME.
[0019] In some embodiments, the make-up fluid comprises propane.
[0020] In some embodiments, the make-up fluid is propane.
[0021] In some embodiments, the make-up fluid comprises propane
and dimethyl
ether (DME).
[0022] In some embodiments, the make-up fluid comprises natural
gas liquid
(NGL).
[0023] In some embodiments, the make-up fluid comprises liquefied
petroleum gas
(LPG).
[0024] In some embodiments, the make-up fluid comprises light
catalytic gas oil.
[0025] In some embodiments, the first mobilizing fluid and the
make-up fluid are
different fluids.
[0026] In some embodiments, the second mobilizing fluid is
injected into the
underground reservoir through the first well.
[0027] In some embodiments, the second mobilizing fluid is
injected into the
underground reservoir through the second well.
[0028] In some embodiments, the first well and the second well are
located on a
same pad.
[0029] In some embodiments, the first well and the second well are
located on
different pads.
[0030] In some embodiments, the first produced fluid has a
concentration of the
first mobilizing fluid of at least 60 vol%.
[0031] In some embodiments, the first produced fluid has a
concentration of the
first mobilizing fluid of at least 70 vol%.
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,
[0032] In some embodiments, the first produced fluid has a
concentration of the
first mobilizing fluid of at least 80 vol%.
[0033] In some embodiments, the first produced fluid has a
concentration of the
first mobilizing fluid of at least 90 vol%.
[0034] In some embodiments, the method further comprises mixing at
least a
portion of the second produced fluid with a second make-up fluid to form a
third mobilizing
fluid, injecting the third mobilizing fluid into the underground reservoir
through a third well,
the third mobilizing fluid having a pressure that is above a liquid/vapor
phase change
pressure of the third mobilizing fluid, and producing a third produced fluid
from the
underground reservoir through the third well, the third produced fluid
including bitumen
and at least a portion of the third mobilizing fluid injected into the
underground reservoir.
[0035] In some embodiments, the second well and the third well are
different wells.
[0036] In some embodiments, the second well and the third well are
located on a
same pad.
[0037] In some embodiments, producing the first produced fluid
from the
underground reservoir includes collecting the produced fluid directly from the
first well and
directing at least a portion of the first produced fluid around separation
units of a surface
facility, the separation units used to separate the bitumen and the at least a
portion of the
first mobilizing fluid of the first produced fluid.
[0038] In some embodiments, the at least a portion of the first
produced fluid that
is directed around the separation units of the surface facility is
compositionally
unprocessed.
[0039] In some embodiments, mixing at least a portion of the first
produced fluid
with the make-up fluid to form the second mobilizing fluid includes mixing
less than about
30 vol% of fluid produced per cycle with the make-up fluid to form the second
mobilizing
fluid.
[0040] In some embodiments, mixing at least a portion of the first
produced fluid
with the make-up fluid to form the second mobilizing fluid includes mixing
less than about
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40 vol% of fluid produced per cycle with the make-up fluid to form the second
mobilizing
fluid.
[0041] In some embodiments, mixing at least a portion of the first
produced fluid
with the make-up fluid to form the second mobilizing fluid includes mixing
less than about
50 vol% of fluid produced per cycle with the make-up fluid to form the second
mobilizing
fluid.
[0042] In some embodiments, mixing at least a portion of the first
produced fluid
with the make-up fluid to form the second mobilizing fluid includes mixing
less than about
the first 30 vol% of fluid produced per cycle with the make-up fluid to form
the second
mobilizing fluid.
[0043] In some embodiments, mixing at least a portion of the first
produced fluid
with the make-up fluid to form the second mobilizing fluid includes mixing
less than about
the first 40 vol% of fluid produced per cycle with the make-up fluid to form
the second
mobilizing fluid.
[0044] In some embodiments, mixing at least a portion of the first
produced fluid
with the make-up fluid to form the second mobilizing fluid includes mixing
less than about
the first 50 vol% of fluid produced per cycle with the make-up fluid to form
the second
mobilizing fluid.
[0045] In some embodiments, prior to injecting the first mobilizing fluid
into the
underground reservoir through the first well, the first well has been used to
perform at
least one cycle of a cyclic solvent process of recovering bitumen from the
underground
reservoir, each cycle including: injecting a mobilizing fluid into the
underground reservoir
through the first well; and producing a produced fluid from the underground
reservoir
through the first well, the produced fluid including bitumen and at least a
portion of the
mobilizing fluid injected into the underground reservoir.
[0046] In some embodiments, the first well has been used to perform at
least two
cycles of a cyclic solvent process of recovering bitumen from the underground
reservoir.
[0047] In some embodiments, the first well has been used to perform at
least three
cycles of a cyclic solvent process of recovering bitumen from the underground
reservoir.
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[0048] The foregoing has broadly outlined the features of the present
disclosure so
that the detailed description that follows may be better understood.
Additional features
will also be described herein.
[0049] 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
[0050] 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.
[0051] FIG. 1 is a schematic axial cross-section of a horizontal
wellbore undergoing
a typical CSP showing solvent fingers extending from the wellbore into the
reservoir
during early-stage cycles;
[0052] FIG. 2 is schematic axial cross-section of a horizontal
wellbore undergoing
a typical CSP showing solvent fingers extending from the wellbore into the
reservoir
during mid-stage cycles;
[0053] FIG. 3 is a graph showing production rate over time of solvent
and bitumen
in typical CSPs;
[0054] FIG. 4 is a schematic diagram of a typical bitumen production
and
separation facility;
[0055] FIG. 5 is a graph showing rates of solvent recycling over time
for CSPs;
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[0056]
FIG. 6 is a schematic diagram showing a modified CSP according to one
embodiment where a make-up solvent is added to a produced fluid to be
reinjected into
a wellbore;
[0057]
FIG. 7 is a graph showing a production profile for solvent cut as a function
of hydrocarbons produced per cycle; and
[0058]
FIG. 8 is a block diagram of a method of recovering bitumen from an
underground reservoir penetrated by at least one well.
[0059]
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
[0060]
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
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.
[0061]
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,
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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.
[0062] 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."
[0063] 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.
[0064] A "light hydrocarbon" is a hydrocarbon having carbon numbers in a
range
from 1 to 9.
[0065] "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:
¨ 19 weight (wt.) percent (%) aliphatics (which can range from 5 wt. % to
30 wt. %
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.
[0066] 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
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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.
[0067] "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 10.0 API (density of 1,000 kg/m3 or 1
g/cm3).
An extra heavy oil, in general, has an API gravity of less than 10.0 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.
[0068] 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 10 . The terms viscous oil,
heavy oil, and
bitumen are used interchangeably herein since they may be extracted using
similar
processes.
[0069] 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,
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.
[0070] 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.
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,
[0071] 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."
[0072] 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.
[0073] A "fluid" includes a gas or a liquid and may include, for
example, a produced
or native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold
water, or a mixture
of these among other materials.
[0074] "Facility" or "surface facility" is one or more tangible
pieces of physical
equipment through which hydrocarbon fluids are either produced from a
subterranean
reservoir or injected into a subterranean reservoir, or equipment that can be
used to
control production or completion operations. In its broadest sense, the term
facility is
applied to any equipment that may be present along the flow path between a
subterranean reservoir and its delivery outlets. Facilities may comprise
production wells,
injection wells, well tubulars, wellbore head equipment, gathering lines,
manifolds,
pumps, compressors, separators, surface flow lines, steam generation plants,
processing
plants, and delivery outlets. In some instances, the term "surface facility"
is used to
distinguish from those facilities other than wells.
[0075] 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.
[0076] 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
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k
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.
[0077] "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
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.
[0078] 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.
[0079] 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,
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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.
[0080] In spite of the technologies that have been developed, there
remains a need
in the field for methods of optimizing cyclic solvent processes (CSPs).
[0081] Herein, methods of optimizing the solvent use in the CSPs are
described.
The methods include recycling a produced fluid within a process facility,
particularly when
the produced fluid has a high solvent concentration such as when produced
during early-
cycle production. In some embodiments, the methods include a repressurization
and
mixing of the produced fluid with a make-up solvent prior to reinjection into
neighboring
wells to begin an injection period therein.
[0082] Figure 1 shows a schematic axial cross-section of a system 100
including a
horizontal wellbore 102 provided in a formation or reservoir 104. A mobilizing
fluid such
as but not limited to a solvent or a mixture of solvents is generally pumped
down from a
surface through overburden 106 and along the wellbore 102 where it passes into
the
formation 104 via, for example, one of a number of apertures provided in a
wellbore
casing of the wellbore 102.
[0083] In the aforementioned CSPs, solvents may be used to enhance the
extraction of petroleum products from the reservoir 104. In some embodiments,
the
solvent used in the CSPs 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.
[0084] 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% C2-05 hydrocarbons on a
mass
basis. The solvent may be greater than 50 mass% propane, optionally with
diluent when
it is desirable to adjust the properties of the injectant to improve
performance.
[0085]
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.
[0086]
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.
[0087]
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.
[0088]
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.
[0089]
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).
[0090]
As the mobilizing fluid is injected, the mobilizing fluid passes into the
formation 104 and reduces the viscosity of the petroleum products therein and
allows
them to flow towards the wellbore 102, where it passes into the wellbore 102
via one of a
number of apertures provided in the wellbore casing (not shown).
[0091]
In some embodiments, during early-stage cycles, after injection of a
mobilizing fluid through the wellbore 102, the mobilizing fluid forms
"fingers" such as the
fingers 108 shown in Figure 1 extending from the wellbore 102 into the
reservoir 104;
[0092]
In some embodiments, in later injection cycles, larger volumes of mobilizing
fluid need to be injected into wellbore 102 to extract bitumen and/or
petroleum products
therefrom. Figure 2 is schematic axial cross-section of horizontal wellbore
102 during a
later cycle of a CSP, showing solvent fingers 108 extending from the wellbore
102 into
the reservoir 104. In this embodiment, a region 110 of mobilizing fluid
generally forms
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. . .
around the wellbore 102. Mobilizing fluid present in the region 110 generally
does not
interact with the bitumen and/or petroleum products present in the reservoir
104 and
therefore, this portion of the injected solvent is not efficiently utilized
for extracting bitumen
from the reservoir. Accordingly, upon extraction of a produced fluid from the
wellbore 102,
the produced fluid in these later injection cycles of CSP process generally
has a high
concentration of mobilizing fluid.
[0093] Referring now to Figure 3, illustrated therein is a graph
300 showing typical
production rate curves of mobilizing fluid 302 and bitumen 304 over time in
the life cycle
of a well utilizing a typical CSP. The life cycle of a well is utilizing a
typical CSP is generally
in the range of 5-10 years. Region 306 shows an optimum time frame in the
early life
cycle (e.g. first 0-2 years) for recycling mobilizing fluid produced from a
CSP as it indicates
the period of time where the production rate of mobilizing fluid from the
reservoir is
greatest.
[0094] Referring now to Figure 4, illustrated therein is a
schematic diagram of a
layout of a facility 400 for for recovering fluid from an underground
reservoir and
separating it into bitumen and a mobilizing fluid, according to one
embodiment. Facility
400 includes a CSP pad 402 that includes one or more wellbores (such as
wellbore 102),
surface facilities 404 and a production pipeline 406. In some embodiments, CSP
pad 402
includes about 24 wells. In other embodiments, CSP pad 402 includes about 28
wells.
[0095] CSP pad 402 is used to perform cyclic injection and
production operations
to recover bitumen from an underground reservoir. In the embodiment shown in
Figure 4,
during injection cycles, mobilizing fluid stored in a unit of the surface
facilities 404 (e.g.
storage unit 408) is injected through a wellhead and into the underground
reservoir via a
wellbore. In some embodiments, a flow assurance solvent stored in the surface
facilities
404 may also be injected with the mobilizing fluid into the underground
reservoir.
[0096] In the embodiment shown in Figure 4, during production
cycles, a produced
fluid is recovered from the underground reservoir via a wellbore of wellbore
CSP pad 402.
The produced fluid generally includes hydrocarbons such as but not limited to
bitumen
and the mobilizing fluid. The hydrocarbons recovered from the underground
reservoir are
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generally processed in one or more units in the surface facilities 404 to
separate the
injected mobilizing fluid from the bitumen.
[0097] Herein, the surface facilities 404 includes a collection of
mobilizing fluid
processing units 404a and associated pipeline that carries the mobilizing
fluid and/or the
flow assurance solvent to the CSP pad 402 to be injected into the underground
reservoir.
Surface facilities 404 also includes a collection of produced fluid processing
units 404b
used to process the produced fluid from the underground reservoir and
associated
pipeline that carries the produced fluid from the CSP pad 402 towards the
production
pipeline 406.
[0098] In the embodiment shown in Figure 4, mobilizing fluid processing
units 404a
include but are not limited to storage unit(s) 408, a mobilizing fluid pump
and/or
compressor 409 and an injection heater 411. In other embodiments, the
mobilizing fluid
processing units 404a may also include a makeup pump/compressor (not shown).
[0099] In the embodiment shown in Figure 4, produced fluid processing
units 404b
include but are not limited to a casing gas compressor 410, a production
heater 412, a
separator 414, a mobilizing fluid compressor 415, a mobilizing fluid condenser
416 and a
bitumen product pump 417.
[0100] Production pipeline 406 generally refers to a pipeline for
carrying bitumen
to a bitumen processing plant for further processing.
[0101] Facility 400 also includes an unprocessed recycle stream 418.
Herein,
"unprocessed" refers to the notion that recycle stream 418 has not been
seprated into
individual compositional components such as may occur in separator 414 as
shown in
Figure 4. Recycle stream 418 generally connects the produced fluid processing
units
404b and the mobilizing fluid processing units 404a to provide for at least a
portion of the
produced fluid recovered from a wellbore of the CSP pad 402 to bypass any
separation
and processing and be recycled to the mobilizing fluid processing units 404a
to be,
subsequently, reinjected into a wellbore of the CSP pad 402. In some
embodiments, the
portion of the produced fluid that is recycled through the recycle stream 418
to the
mobilizing fluid processing units 404a can be reinjected into the same
wellbore of the
CSP pad 402 as it was originally produced. In some embodiments, the portion of
the
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produced fluid that is recycled through the recycle stream 418 to the
mobilizing fluid
processing units 404a can be reinjected into a different wellbore of the CSP
pad 402 from
that which it was originally injected. In other embodiments, the portion of
the produced
fluid that is recycled through the recycle stream 418 to the mobilizing fluid
processing
units 404a can be reinjected into a different pad than CSP pad 402 (separate
pad not
shown in figure).
[0102] Specifically, as shown in Figure 4, recycle stream 418 directs at
least a
portion of the produced fluid received by the produced fluid processing units
404b from
the CSP pad 402 to the mobilizing fluid processing units 404a upstream (i.e.
prior to) the
produced fluid being separated into a mobilizing fluid and bitumen by
separator 414. For
instance, the recycle stream 418 can intersect a pipeline positioned between
an outlet
from the CSP pad 402 and an inlet to the separator 414. In this manner, in the
embodiments described herein, separator 414 may be sized to only separate a
portion of
the produced fluid received by the produced fluid processing units 404b from
the CSP
pad 402. An example of this reduced capacity of the separator 414 is shown in
Figure 5,
which shows an exemplary graph 500 of solvent produced and recycled over time
for a
CSP. As shown therein, the solvent separation and compression capacity of
facility 400
could be reduced from a peak capacity shown by line 502 to a reduced capacity
shown
by line 504 when a recycle stream such as recycle stream 418 shown in Figure 4
redirects
at least a portion of the produced fluid received by the produced fluid
processing units
404b from the CSP pad 402 to the mobilizing fluid processing units 404a
upstream of the
separator 414.
[0103] In some embodiments, recycle stream 418 directs at least a portion
of the
produced fluid received by the produced fluid processing units 404b from the
CSP pad
402 to a position within the mobilizing fluid processing units 404a upstream
of an inlet to
the CSP pad 402. In some embodiments, recycle stream 418 directs at least a
portion of
the produced fluid received by the produced fluid processing units 404b from
the CSP
pad 402 to a position within the mobilizing fluid processing units 404a
downstream of an
outlet of the storage unit(s) 408.
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[0104] Turning now to Figure 6, illustrated therein is a schematic
diagram of a
system 600 of using a first produced fluid 603 from a first wellbore 602 of a
pad 601
operated under a CSP, according to one embodiment. In the system 600, the
produced
fluid 603 is combined with a first make-up fluid 604 to form a second
mobilizing fluid 605
that is injected into a second wellbore 606 of the pad 601 operated under a
CSP. The first
produced fluid 603 comprises bitumen and at least a portion of a first
mobilizing fluid
injected into the first wellbore 602. In the embodiment shown, a second
produced fluid
607 is produced from the second wellbore 606 and is mixed with a second make-
up fluid
608 to form a third mobilizing fluid 609 that is injected into a third
wellbore 610 of the pad
601 operated under a CSP.
[0105] It should be noted that in some embodiments, first wellbore 602
and second
wellbore 606 can be a same wellbore or can be different wellbores. Further, in
some
embodiments, second wellbore 606 and third wellbore 610 can be the same
wellbore or
can be different wellbores. Further still, in some embodiments, the first
wellbore 602 and
the third wellbore 610 can be a same wellbore or different wellbores. First,
second and
third wellbores 602, 606 and 610 respectively, can be located on a same pad
(e.g. pad
601) or can be located on separate pads, provided that the wells share
processing
facilities.
[0106] It should be noted that first and second produced fluids 603 and
607,
respectively, can be produced during early production cycles, where herein
"early
production cycles" refers to the first two cycles of the CSP, or during later
production
cycles, where herein "later production cycles" refers to a third cycle or
greater of the CSP.
In some embodiments, the use of the first and second produced fluids 603 and
607,
respectively, may be more feasible during later production cycles, after the
near-wellbore
bitumen has been depleted. Generally, later production cycles of a CSP produce
mostly-
pure (e.g. >90% by volume) mobilizing fluid (e.g. solvent) for extended
periods of time,
as shown in Figure 7 where line 702 represents a first CSP cycle, line 704
represents a
second CSP cycle, line 706 represents a third CSP cycle and line 708
represents a fourth
CSP cycle for a single well. These curves show that the well experiences an
increase in
recovered solvent as the well goes through additional CSP cycles.
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[0107] The first mobilizing fluid injected into the first wellbore 602
may have a
temperature in a range of about 30 C to about 90 C and the first make-up
fluid 604 may
also have a temperature in a range of about 30 C to about 90 C. The first
mobilizing
fluid may be propane or may comprise propane. The first mobilizing fluid may
also
comprise dimethyl ether (DME). The first make-up fluid 604 may be or may
comprise
DME. The second make-up fluid 608 may also have a temperature in a range of
about 30
C to about 90 C and may be or may comprise DME. The second make-up fluid 608
may
be the same fluid as the first make-up fluid 604 or may be a different fluid.
[0108] In some embodiments, the first produced fluid 603 may have a
concentration of the first mobilizing fluid of at least 60 vol%. In some
embodiments, the
first produced fluid 603 may have a concentration of the first mobilizing
fluid of at least 70
vol%. In some embodiments, the first produced fluid 603 may have a
concentration of the
first mobilizing fluid of at least 80 vol%. In some embodiments, the first
produced fluid 603
may have a concentration of the first mobilizing fluid of at least 90 vol%.
[0109] In some embodiments, the second mobilizing fluid 605 may include
less
than about 30 vol%, less than about 40 vol% or less than about 50 vol% of the
first
produced fluid 603 produced during that cycle. In some embodiments, the second
mobilizing fluid 605 may include less than about 30 vol%, less than about 40
vol% or less
than about 50 vol% of the first produced fluid 603 produced during that cycle.
[0110] Similarly, in some embodiments, the third mobilizing fluid 609 may
only
include about the first 40 vol% of the second produced fluid 607 produced
during that
cycle.
[0111] In some embodiments, prior to injecting the first mobilizing fluid
into the
underground reservoir through the first well 602, the first well 602 may be
used to perform
at least one cyclic solvent process of recovering bitumen from the underground
reservoir.
Each cyclic solvent process for bitumen recovery includes injecting a
mobilizing fluid into
the underground reservoir through the first well 602 and producing a produced
fluid from
the underground reservoir through the first well 602, the produced fluid
including bitumen
and at least a portion of the mobilizing fluid injected into the underground
reservoir.
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,
[0112] In some embodiments, prior to injecting the first
mobilizing fluid into the
underground reservoir through the first well 602, the first well 602 may be
used to perform
two cyclic solvent processes of recovering bitumen from the underground
reservoir.
[0113] In some embodiments, prior to injecting the first
mobilizing fluid into the
underground reservoir through the first well 602, the first well 602 may be
used to perform
three cyclic solvent processes of recovering bitumen from the underground
reservoir.
[0114] Figure 8 is a block diagram of a method 800 of recovering
bitumen from an
underground reservoir penetrated by at least one well. Method 800 includes a
step 802
of injecting a first mobilizing fluid into the underground reservoir through a
first well. The
first mobilizing fluid has a pressure that is above a liquid/vapor phase
change pressure of
the first mobilizing fluid.
[0115] Method 800 also includes a step 804 of producing a first
produced fluid from
the underground reservoir through the first well. The first produced fluid
includes bitumen
and at least a portion of the first mobilizing fluid injected into the
underground reservoir.
In some embodiments, at least a portion of the first produced fluid from the
underground
reservoir is
[0116] Method 800 also includes a step 806 of mixing at least a
portion of the first
produced fluid with a make-up fluid to form a second mobilizing fluid. In some
embodiments, the portion of the produced fluid that is mixed with the make-up
fluid is un-
separated (i.e. bypasses a separator of surface facility units) when it is
mixed with the
make-up fluid. In this manner, the portion of the produced fluid may also be
referred to as
being compositionally unprocessed after it is produced from the underground
reservoir
when it is mixed with the make-up fluid.
[0117] Method 800 also includes a step 808 of injecting the second
mobilizing fluid
into the underground reservoir through a second well. The second mobilizing
fluid has a
pressure that is above a liquid/vapor phase change pressure of the second
mobilizing
fluid.
[0118] Method 800 also includes a step 810 of producing a second
produced fluid
from the underground reservoir through the second well. The second produced
fluid
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-
includes bitumen and at least a portion of the second mobilizing fluid
injected into the
underground reservoir.
[0119] 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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