Note: Descriptions are shown in the official language in which they were submitted.
CA 02893221 2015-10-22
MOBILIZING COMPOSITION FOR USE IN GRAVITY DRAINAGE PROCESS
FOR RECOVERING VISCOUS OIL
AND
START-UP COMPOSITION FOR USE IN A START-UP PHASE OF A PROCESS FOR
RECOVERING VISCOUS OIL FROM AN UNDERGROUND RESERVOIR
FIELD OF THE INVENTION
MOBILIZING COMPOSITION
[0001] The disclosure relates generally to hydrocarbon recovery from
underground
reservoirs. More specifically, the disclosure relates to mobilizing
compositions for use in
gravity drainage processes for recovering viscous oil and to the processes
themselves.
START-UP COMPOSITION
[0002] The disclosure also relates generally to hydrocarbon recovery from
underground reservoirs. More specifically, the disclosure relates to start-up
compositions for
use in a start-up phase of a process for recovering viscous oil.
BACKGROUND OF THE INVENTION
MOBILIZING COMPOSITION
[0003] This section is intended to introduce various aspects of the art,
which may be
associated with the present disclosure. This discussion is believed to assist
in providing 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 admissions of prior art.
[0004] Modern society is greatly dependent on the use of hydrocarbon
resources for
fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface
formations
that can be termed "reservoirs". Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the subsurface formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
subsurface formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to
1
CA 02893221 2015-10-22
satisfy future energy needs. As the prices of hydrocarbons increase, the less
accessible
sources become more economically attractive.
[0005] Recently, the harvesting of oil sands to remove heavy oil has
become more
economical. Hydrocarbon removal from oil sands may be performed by several
techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot
gas, solvents, or a
combination thereof, can be injected to release the hydrocarbons. The released
hydrocarbons may be collected by wells and brought to the surface.
[0006] Bitumen and heavy oil (collectively referred to herein as "viscous
oil" as further
defined below) reserves exist at varying depths beneath the earth's surface.
More shallow
reserves are often mined followed by surface extraction. Deeper reserves are
often exploited
by in situ processes.
[0007] Diluting agents have been used for both in situ and surface
extraction
processes to dilute viscous oil. The term "solvent" is often used in the
industry and literature
in place of "diluting agent".
[0008] Diluting agents reduce the viscosity of viscous oil by dilution,
while steam
reduces the viscosity of viscous oil by raising the viscous oil temperature.
Reducing the
viscosity of in situ viscous oil is done to permit or facilitate its
production.
[0009] Where deposits lie well below the surface, viscous oil may be
extracted using
in situ ("in place") processes. Thermal recovery processes are one category of
in situ
processes, where steam is used to reduce the viscosity of the viscous oil.
These processes
are referred to as steam-based processes. One example of an in situ thermal
process is the
steam-assisted gravity drainage method (SAGD). In SAGD, directional drilling
is employed to
place two horizontal wells in the oil sands ¨ a lower well and an upper well
positioned above
it. Steam is injected into the upper well to heat the bitumen and lower its
viscosity. The
bitumen and condensed steam will then drain downward through the reservoir
under the
action of gravity and flow into the lower production well, whereby these
liquids can be
pumped to the surface. At the surface of the well, the condensed steam and
bitumen are
separated, and the bitumen is diluted with appropriate light hydrocarbons for
transport to a
refinery or an upgrader. An example of SAGD is described in U.S. Patent No.
4,344,485
(Butler).
[0010] Cyclic Steam Stimulation (CSS) is a thermal recovery process in
which the
same well is used both for injecting a fluid and for producing oil. In CSS,
cycles of steam
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injection, soak, and oil production are employed. Once the production rate
falls to a given
level, the well is put through another cycle of injection, soak, and
production. An example of
CSS is described in U.S. Patent No. 4,280,559 (Best).
[0011] Steam Flooding (SF) is an in situ thermal process that involves
injecting
steam into the formation through an injection well. Steam moves through the
formation,
mobilizing oil as it flows toward the production well. Mobilized oil is swept
to the production
well by the steam drive. An example of steam flooding is described in U.S.
Patent No.
3,705,625 (Whitten).
[0012] Other steam-based thermal processes include Solvent-Assisted
Steam-Assisted Gravity Drainage (SA-SAGD), an example of which is described in
Canadian Patent No. 1,246,993 (Vogel); Liquid Addition to Steam for Enhanced
Recovery
(LASER), an example of which is described in U.S. Patent No. 6,708,759 (Leaute
et al.);
Combined Steam and Vapour Extraction Process (SAVEX), an example of which is
described in U.S. Patent No. 6,662,872 (Gutek et al.), and derivatives
thereof. These
processes employ a "diluting agent" with steam.
[0013] Solvent-dominated recovery processes (SDRPs) are another category
of in
situ processes, where solvent is used to reduce the viscosity of the viscous
oil. At the present
time, solvent-dominated recovery processes (SDRPs) are rarely used to produce
highly
viscous oil. Vapour Extraction (VAPEX) is an example of SDRP, which is
described in U.S.
Patent No. 5,899,274 (Frauenfeld). In certain described SDRPs, the solvent is
heated as in,
for example, heated-VAPEX (H-VAPEX), which is VAPEX using a heated diluting
agent.
[0014] It is desirable to provide an improved or alternative mobilizing
composition for
use in gravity drainage processes for recovering viscous oil from an
underground reservoir.
START-UP COMPOSITION
[0015] This section is intended to introduce various aspects of the art,
which may be
associated with the present disclosure. This discussion is believed to assist
in providing 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 admissions of prior art.
[0016] Modern society is greatly dependent on the use of hydrocarbon
resources for
fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface
formations
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CA 02893221 2015-10-22
that can be termed "reservoirs". Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the subsurface formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
subsurface formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to
satisfy future energy needs. As the prices of hydrocarbons increase, the less
accessible
sources become more economically attractive.
[0017] Recently, the harvesting of oil sands to remove heavy oil has
become more
economical. Hydrocarbon removal from oil sands may be performed by several
techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot
gas, solvents, or a
combination thereof, can be injected to release the hydrocarbons. The released
hydrocarbons may be collected by wells and brought to the surface.
[0018] Bitumen and heavy oil (collectively referred to herein as "viscous
oil" as further
defined below) reserves exist at varying depths beneath the earth's surface.
More shallow
reserves are often mined followed by surface extraction. Deeper reserves are
often exploited
by in situ processes. Where deposits lie well below the surface, viscous oil
may be extracted
using in situ ("in place") techniques.
[0019] Diluting agents have been used for both in situ and surface
extraction
processes to dilute viscous oil. The term "solvent" is often used in the
industry and literature
in place of "diluting agent". Diluting agents that have previously been
suggested for viscous
oil recovery include n-alkanes, such as ethane, propane, and butane, n- and
iso-pentane,
cycloalkanes like cyclopentane and cyclohexane, and gas plant condensates (a
mixture of
n-alkanes, naphthenes and aromatics).
[0020] Diluting agents reduce the viscosity of viscous oil by dilution,
while steam
reduces the viscosity of viscous oil by raising the viscous oil temperature.
Reducing the
viscosity of in situ viscous oil is done to permit or facilitate its
production.
[0021] Where deposits lie well below the surface, viscous oil may be
extracted using
in situ ("in place") processes. Thermal recovery processes are one category of
in situ thermal
processes, where steam is used to reduce the viscosity of the viscous oil.
These processes
are referred to as steam-based processes. One example of an in situ thermal
process is the
steam-assisted gravity drainage method (SAGD). In SAGD, directional drilling
is employed to
place two horizontal wells in the oil sands ¨ a lower well and an upper well
positioned above
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CA 02893221 2015-10-22
it. Steam is injected into the upper well to heat the bitumen and lower its
viscosity. The
bitumen and condensed steam will then drain downward through the reservoir
under the
action of gravity and flow into the lower production well, whereby these
liquids can be
pumped to the surface. At the surface of the well, the condensed steam and
bitumen are
separated, and the bitumen is diluted with appropriate light hydrocarbons for
transport to a
refinery or an upgrader. An example of SAGD is described in U.S. Patent No.
4,344,485
(Butler).
[0022] In other in situ thermal processes, such as in Cyclic Steam
Stimulation (CSS),
the same well is used both for injecting a fluid and for producing oil. In
CSS, cycles of steam
injection, soak, and oil production are employed. Once the production rate
falls to a given
level, the well is put through another cycle of injection, soak, and
production. An example of
CSS is described in U.S. Patent No. 4,280,559 (Best).
[0023] Steam Flooding (SF) is an in situ thermal process that involves
injecting
steam into the formation through an injection well. Steam moves through the
formation,
mobilizing oil as it flows toward the production well. Mobilized oil is swept
to the production
well by the steam drive. An example of steam flooding is described in U.S.
Patent No.
3,705,625 (Whitten).
[0024] Another in situ thermal processes include Solvent-Assisted Steam-
Assisted
Gravity Drainage (SA-SAGD), an example of which is described in Canadian
Patent No.
1,246,993 (Vogel); Liquid Addition to Steam for Enhanced Recovery (LASER), an
example
of which is described in U.S. Patent No. 6,708,759 (Leaute et al.); Combined
Steam and
Vapour Extraction Process (SAVEX), an example of which is described in U.S.
Patent No.
6,662,872 (Gutek at al.); and derivatives thereof. These processes employ a
relatively small
amount of solvent or "diluting agent" in steam-dominated recovery processes
[0025] Solvent-dominated recovery processes (SDRPs) are another category
of in
situ processes, where solvent is used to reduce the viscosity of the viscous
oil. At the present
time, solvent-dominated recovery processes (SDRPs) are rarely used to produce
highly
viscous oil. Vapour Extraction (VAPEX) is an example of SDRP, which is
described in U.S.
Patent No. 5,899,274 (Frauenfeld). In certain described SDRPs, the solvent is
heated.
Heated-VAPEX (H-VAPEX) is VAPEX using a heated diluting agent.
[0026] Cyclic solvent-dominated recovery processes (CSDRPs) have also
been
proposed. CSDRPs are a subset of SDRPs. A CSDRP may be, but is not
necessarily, a
CA 02893221 2015-10-22
generally non-thermal recovery method that uses a solvent (or "diluting
agent") to mobilize
viscous oil by cycles of injection and production. In a CSDRP, a viscosity-
reducing solvent is
injected through a well into a subterranean viscous-oil reservoir, causing the
pressure to
increase. Next, the pressure is lowered and reduced-viscosity oil is produced
to the surface
through the same well through which the solvent was injected. Multiple cycles
of injection
and production are used. In some instances, a well may not undergo cycles of
injection and
production, but only cycles of injection or only cycles of production. CSDRPs
may be
particularly attractive for thinner or lower-oil-saturation reservoirs. In
such reservoirs, thermal
methods utilizing heat to reduce viscous oil viscosity may be inefficient due
to excessive heat
loss to the overburden and/or underburden and/or reservoir with low oil
content. References
describing specific CSDRPs include: Canadian Patent No. 2,349,234 (Lim et
a/.); Lim et a/.,
"Three-dimensional Scaled Physical Modeling of Solvent Vapour Extraction of
Cold Lake
Bitumen", The Journal of Canadian Petroleum Technology, 35(4), pp. 32-40,
April 1996; Lim
et a/., "Cyclic Stimulation of Cold Lake Oil Sand with Supercritical Ethane",
SPE Paper
30298, 1995; US Patent No. 3,954,141 (Allen etal.); and Feali et al.,
"Feasibility Study of the
Cyclic VAPEX Process for Low Permeable Carbonate Systems", International
Petroleum
Technology Conference Paper 12833, 2008. The family of processes within the
Lim et al.
references describes embodiments of a particular SDRP that is also a cyclic
solvent-dominated recovery process (CSDRP). These processes relate to the
recovery of
heavy oil and bitumen from subterranean reservoirs using cyclic injection of a
solvent in the
liquid state which vapourizes upon production. The family of processes within
the Lim et al.
references may be referred to as CSPTM processes. Another example of a CSDRP
is
described in Canadian Patent Document No. 2,688,392 (Lebel et al., published
June 9,
2011).
[0027] In certain predominantly non-thermal CSDRPs, while heat is not
used to
reduce the viscosity of the viscous oil, the use of heat is not excluded.
Heating may be
beneficial to improve performance or start-up. For start-up, low-level heating
(for example,
less than 100 C) may be appropriate. Low-level heating of the solvent prior to
injection may
also be performed to prevent hydrate formation in tubulars and in the
reservoir. Heating to
higher temperatures may also benefit recovery.
[0028] Before commencing an in situ process, a start-up phase may occur.
The
start-up phase may condition the reservoir for viscous oil extraction and
production by the
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CA 02893221 2015-10-22
recovery processes. Without a start-up phase, viscous oil may be too viscous
and immobile.
Consequently, it may be difficult for an extraction fluid to penetrate a
viscous oil-containing
region, to the extent required for a steam-based or solvent-dominated viscous
oil recovery
process.
[0029] Some start-up phases for SAGD use heat circulation. For example,
steam and
surfactant may be used to create a foam, as disclosed in US Patent 5,215,146,
a heated fluid
may be injected, as disclosed in WO 1999/067503 or CA 2,697,417, or the
wellbores may be
presoaked as disclosed in WO 2012/037147 or US 2011/0174488.
[0030] Another start-up phase for SAGD, disclosed in CA 2,766,838,
discloses
wellbore pair configured to force an initial fluid communication between the
production well
bore and the injection wellbore to occur at a selected region along the
production wellbore
and injection wellbore.
[0031] Another start-up phase for SAGD, disclosed in CA 2,740,941,
discloses
relying on the injection of a start-up fluid at elevated pressures in the
injection wellbore. A
production wellbore is used to create a pressure sink (voidage) to maximize
the available
pressure gradient between the production and injection wellbores and as a
result help draw
the start-up fluid towards the production wellbore. The process is applied
after the production
wellbore has been completed with production tubing, artificial lift has been
installed or is
operational. Measuring the reproduced start-up fluid and storing or
transporting the produced
fluids once they are produced to surface are described. The volume of start-up
fluid required
is substantial, with the representative calculations suggesting required start-
up fluid volumes
of 500-18,000 meters cubed (m3) to treat a single wellbore pair. A single
wellbore pair
includes a single production wellbore and a single injection wellbore.
[0032] WO 2012/121711 discloses delivering a small reduction in the time
duration of
the start-up phase time requirements and no real capital cost reduction
benefits as the
equipment required to circulate steam in the extraction process of heavy oil
must be in place
before the start-up phase. WO 2012/121711 discloses fluid circulation followed
by a
"squeeze step" (described as the shut-off of fluid returns in a wellbore and
the inspection of
an increase in fluid production at another wellbore).
[0033] WO 2013/071434 discloses that in order to accelerate the start-up
phase of a
SAGD wellbore pair, it is preferable to establish a physical connection
between the injection
and production wellbores. The physical connection can be established by: (1)
drilling the
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CA 02893221 2015-10-22
injection and production wellbores such that the toes of wellbores intercept;
(2) drilling a
vertical wellbore that intercepts the toe locations of the injection and
production wellbores
(creating the physical connection via it's wellbore); or (3) propagating a
fracture between the
toe locations of the injection and production wellbores. Thus, WO 2013/071434
discloses
that, by creating a physical connection (or a high permeability path by
fracturing), it is
possible to create a continuous unidirectional pathway between the injection
and production
wellbores for the heated fluids used to start-up the wellbores. At the end of
the start-up
phase, it may then be necessary to plug the intersection point connecting the
injection and
production wellbores. Hence, the start-up phase disclosed in WO 2013/071434
may be
complex and expensive to implement.
[0034] CA 2,698,898 discloses a method of initiating or accelerating
fluid
communication between horizontal wellbores located in a formation of very
limited fluid
mobility at start-up. A selected amount of a diluent such as xylene, benzene,
toluene or
phenol, is injected at sub-fracturing conditions and ambient temperature into
a first of the
wellbores. The method may be employed for a start-up phase for the recovery of
heavy oil
using, for example, steam-assisted gravity drainage.
[0035] It is desirable to provide an improved or alternative start-up
composition for
use in a start-up phase of a process for recovering viscous oil from an
underground
reservoir.
SUMMARY OF THE INVENTION
MOBILIZING COMPOSITION
[0036] Generally, described herein is a mobilizing composition for use in
a gravity
drainage process for recovering viscous oil from an underground reservoir. The
mobilizing
composition may comprise (i) 75-98 vol. % diluting agent; (ii) 2-25 vol. %
steam having a
steam quality of at least 5%; and (iii) 0-5 vol. % accelerating agent for
accelerating
penetration of the diluting agent into the viscous oil.
START-UP COMPOSITION
[0037] Generally, described herein is a start-up composition for use in a
start-up
phase of a process for recovering viscous oil from an underground reservoir.
The start-up
composition comprises (i) 74.9-97.9 vol. % diluting agent; (ii) 2-25 vol. %
steam having a
8
CA 02893221 2015-10-22
steam quality of at least 5%; and (iii) 0.1-5 vol. % accelerating agent for
accelerating
penetration of the diluting agent into the viscous oil.
[0038] Other aspects and features of the present invention will become
apparent to
those ordinarily skilled in the art upon review of the following description
of specific
embodiments of the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
MOBILIZING COMPOSITION
[0039] These and other features, aspects and advantages of the disclosure
will
become apparent from the following description, appending claims and the
accompanying
drawings, which are briefly described below.
[0040] Fig. 1 is a flow chart of a gravity drainage process for
recovering viscous oil
from an underground reservoir.
[0041] Figs 2 to 12 depict simulation results.
[0042] Fig. 2 is a graph illustrating penetrating rate.
[0043] Fig. 3 is a graph illustrating bitumen rate.
[0044] Fig. 4 is a graph illustrating (Yo increase in cumulative bitumen.
[0045] Fig. 5 is a graph illustrating bitumen rate increase.
[0046] Fig. 6 is a graph illustrating C7 injection rate.
[0047] Fig. 7 is a graph illustrating % decrease in cumulative C7
injection.
[0048] Fig. 8 is a graph illustrating diluting agent recovery.
[0049] Fig. 9 is a graph illustrating bitumen recover per diluting agent
left in the
reservoir.
[0050] Fig. 10 illustrates two vapor chambers.
[0051] Fig. 11 illustrates two temperature fronts.
[0052] Fig. 12 illustrates C7 advancement in a reservoir.
START-UP COMPOSITION
[0053] Fig. 13 is a flow chart of a gravity drainage process for
recovering viscous oil
from an underground reservoir.
[0054] Figs 14 to 18 depict simulation results.
[0055] Fig. 14 is a graph illustrating penetrating rate.
[0056] Fig. 15 is a graph illustrating bitumen rate.
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CA 02893221 2015-10-22
[0057] Fig. 16 illustrates two vapour chambers at 150 days.
[0058] Fig. 17 illustrates two vapour chambers at 190 days.
[0059] Fig. 18 is a graph illustrating % increase in cumulative bitumen.
[0060] It should be noted that the figures are merely examples and no
limitations on
the scope of the present disclosure are intended thereby. Further, the figures
are generally
not drawn to scale, but are drafted for purposes of convenience and clarity in
illustrating
various aspects of the disclosure.
DETAILED DESCRIPTION
[0061] For the purpose of promoting an understanding of the principles of
the
disclosure, reference will now be made to the features illustrated in the
drawings and specific
language will be used to describe the same. It will nevertheless be understood
that no
limitation of the scope of the disclosure is thereby intended. 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. It will be apparent to those skilled in the relevant art
that some features
that are not relevant to the present disclosure may not be shown in the
drawings for the sake
of clarity.
[0062] At the outset, for ease of reference, certain terms used in this
application and
their meaning, as used in this context, are set forth below. 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 processes are not limited by the usage of the terms shown below,
as all
equivalents, synonyms, new developments and terms or processes that serve the
same or a
similar purpose are considered to be within the scope of the present
disclosure.
[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] "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending
CA 02893221 2015-10-22
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. % - 30 wt.
%, or
higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and
some amount of sulfur (which can range from 2 to 7 wt. %, or higher).
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.
[0065] "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.
[0066] 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
(centipoise) 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 American
Petroleum Institute
(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.
[0067] 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
11
CA 02893221 2015-10-22
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 below the earth's
surface.
[0068] 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.
[0069] 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 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.
[0070] The articles "the", "a" and "an" are not necessarily limited to
mean only one,
but rather are inclusive and open ended so as to include, optionally, multiple
such elements.
[0071] "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
12
CA 02893221 2015-10-22
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.
[0072] 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.
[0073] As used herein, the phrase, "for example," the phrase, "as an
example,"
and/or simply the term "example," when used with reference to one or more
components,
features, details, structures, and/or methods according to the present
disclosure, are
intended to convey that the described component, feature, detail, structure,
and/or method is
an illustrative, non-exclusive example of components, features, details,
structures, and/or
methods according to the present disclosure. Thus, the described component,
feature, detail,
structure, and/or method is not intended to be limiting, required, or
exclusive/exhaustive; and
other components, features, details, structures, and/or methods, including
structurally and/or
functionally similar and/or equivalent components, features, details,
structures, and/or
methods, are also within the scope of the present disclosure.
MOBILIZING COMPOSITION
[0074] Diluting agents that have previously been suggested for viscous
oil recovery
include, but are not limited to, n-alkanes, such as ethane, propane, and
butane, n- and iso-
pentane, cycloalkanes like cyclopentane and cyclohexane, and gas plant
condensates (a
mixture of n-alkanes, naphthenes and aromatics).
[0075] Described herein is a mobilizing composition for use in a gravity
drainage
process for recovering viscous oil from an underground reservoir. The
mobilizing composition
may comprise (i) 75-98 vol. % diluting agent; (ii) 2-25 vol. % steam having a
steam quality of
at least 5%; and (iii) 0-5 vol. % accelerating agent for accelerating
penetration of the diluting
agent into the viscous oil. The vol. A, in each item is at standard
temperature and pressure
(STP).
[0076] The diluting agent may comprise a non-polar hydrocarbon with 2 to
30 carbon
atoms. The diluting agent may comprise at least 50 wt. % of a non-polar
hydrocarbon with 2
to 30 carbon atoms. The diluting agent may comprise a C2-C30 alkane. The
diluting agent
may comprise at least 50 wt. % of a C2-C30 alkane. The diluting agent may
comprise a
C2-C30 n-alkane. The diluting agent may comprise at least 50 wt. % of a C2-C30
n-alkane.
13
CA 02893221 2015-10-22
The diluting agent may comprise a C2-C20 alkane. The diluting agent may
comprise at least
50 wt. % of a C2-C20 alkane. The diluting agent may comprise a C2-C20 n-
alkane. The
diluting agent may comprise at least 50 wt. % of a C2-C20 n-alkane. The
diluting agent may
comprise a C2-05 alkane. The diluting agent may comprise at least 50 wt. % of
a C2-05
alkane. The diluting agent may comprise propane. The diluting agent may
comprise at least
50 wt. % propane. The diluting agent may comprise a C5-C7 cycloalkane. The
diluting agent
may comprise at least 50 wt. % of a C5-C7 cycloalkane. The diluting agent may
comprise
cyclohexane. The diluting agent may comprise at least 50 wt. % of cyclohexane.
The diluting
agent may comprise a mixture of non-polar hydrocarbons, the non-polar
hydrocarbons being
C2-C30 alkanes, the mixture being substantially aliphatic and substantially
non-halogenated.
The diluting agent may comprise at least 50 wt. % of a mixture of non-polar
hydrocarbons,
the non-polar hydrocarbons being C2-C30 alkanes, the mixture being
substantially aliphatic
and substantially non-halogenated. "Substantially aliphatic and substantially
non-halogenated" means less than 10% by weight of aromaticity and with no more
than 1
mole percent halogen atoms. The level of aromaticity may be less than 5, less
than 3, less
than 1, or 0 % by weight. The diluting agent may comprise a mixture of non-
polar
hydrocarbons and may be a gas plant condensate comprising at least one C3-C17
n-alkane,
at least one C5-C7 cycloalkane, and at least one C6-C8 aromatic hydrocarbon.
The diluting
agent may be present in an amount of 75-98 vol. % or 87-96 vol. % in the
composition at
STP.
[0077] The diluting agent may be a fluid of a lower viscosity and lower
density than
those of the viscous oil being recovered. Its viscosity may, for example, be
0.2 to 5 cP
(centipoise) at room temperature and at a pressure high enough to make it
liquid. Its density
may be, for example, 450 to 750 kg/m3 at 15 C and at a pressure high enough to
make it
liquid. The mixture or the blend of diluting agent and viscous oil may have a
viscosity and a
density that is in between those of the diluting agent and the viscous oil.
The diluting agent
may or may not precipitate asphaltenes if its concentration exceeds a critical
concentration.
The diluting agent may be injected as a liquid, as a heated liquid, as a
vapor, as a mixture of
vapour and liquid, as a supercritical fluid, or as a combination thereof.
[0078] The steam may have a quality (defined as the wt. % of total steam
present as
steam vapour, and the remainder as liquid) of at least 5%, or 10-95%. The
steam may be
present in an amount of 2-25 vol. '%, or 4-8 vol. % in the composition at STP.
The inclusion of
14
CA 02893221 2015-10-22
steam may increase the latent heat of the mobilizing composition, which upon
condensation
transfers more heat than the diluting agent alone to cooler bitumen, raising
its temperature
and reducing its viscosity. For instance, as illustrated in the simulations
described below,
inclusion of only 5 vol. % steam in a steam-C7 mixture increases the mixture's
latent heat by
58% and the total heat by 55% over C7 alone at 201 C (C7 refers to heptane). A
higher
latent heat may reduce the viscosity of bitumen, which may allow more
penetration of diluting
agent into the oil sands matrix, as explained below. The result may be a
larger swept volume
and/or a higher bitumen recovery.
[0079] The steam may be added continuously with the diluting agent or may
be
added intermittently or cyclically with the diluting agent. The steam
injection rate in each
injection period can be the same during intermittent injection or different in
different injection
periods. The injection periods can be the same or variable. Steam rate in
intermittent
injection may be higher than the continuous injection case. The cumulative
steam in the
intermittent steam injection case may be the same as the cumulative steam
injection in the
continuous steam injection case. For example, the steam injection rate can be
x m3/D
(meters3 per day) for the continuous case and 2x m3/D in the injection period
of two
consecutive injection and no-injection periods. The steam injection rate can
be tapered or
increased with time. The steam injection rate at any time can vary between
zero and a
non-zero value.
[0080] The accelerating agent may be present, for example, in an amount
of 0-5 vol.
%, or 0.1 to 5 vol. %, or 0.1 to 1 vol. % in the composition at STP. The
accelerating agent
may comprise propyl acetate. The accelerating agent may comprise at least 50
wt. % of
propyl acetate. The accelerating agent may comprise n-propyl acetate. The
accelerating
agent may comprise at least 50 wt. % of n-propyl acetate. The accelerating
agent may
comprise iso-propyl acetate. The accelerating agent may comprise at least 50
wt. % of iso-
propyl acetate. The accelerating agent may comprise n-propyl acetate, iso-
propyl acetate, or
a combination thereof. The accelerating agent may comprise at least 50 wt. %
of n-propyl
acetate, iso-propyl acetate, or a combination thereof. The accelerating agent
may comprise
ethyl acetate, methyl acetate, isobutyl acetate, propyl acetate, or a
combination thereof. The
accelerating agent may comprise at least 50 wt. % of ethyl acetate, methyl
acetate, isobutyl
acetate, propyl acetate, or a combination thereof. The accelerating agent may
have a boiling
point within (i.e. above or below) 20 C of the steam. The accelerating agent
may have a
CA 02893221 2015-10-22
boiling point within (i.e. above or below) 20 C of the diluting agent. The
accelerating agent
may be blended with the diluting agent or the steam.
[0081] In H-VAPEX, a nonpolar diluting agent such as heptane (C7)
contacts an oil
sands matrix that has a polar water layer around sand grains, and polar-
nonpolar bitumen,
both in the pore space, thereby making the oil sands matrix polar-nonpolar.
The oil sands
matrix, being polar-nonpolar, does not welcome the non-polar heptane. The
penetration of
heptane into the oil sands matrix, therefore, is not very deep. By using a
mobilizing
composition comprising a polar-nonpolar accelerating agent, the mobilizing
composition may
be more welcome by the polar-nonpolar oil sands matrix, thereby potentially
increasing
penetration into the oil sands matrix.
[0082] The mobilizing composition may be injected with other components,
such as:
diesel, aromatic light catalytic gas oil, or another diluting agent, to
provide flow assurance, or
CO2, natural gas, C3+ hydrocarbons, ketones, or alcohols.
[0083] The mobilizing composition may be used in a gravity drainage
process for
recovering viscous oil from an underground reservoir. The use may be for
injecting the
mobilizing composition into a well completed in the underground viscous oil
reservoir to
mobilize the viscous oil. The use may be intermittent with another mobilizing
composition.
The another mobilizing composition may comprise the diluting agent.
[0084] While reference is made herein to the use of the mobilizing
composition, this
is intended to include the use of the mobilizing composition, or its
components. That is, the
components (i), (ii), and, if present, (iii), need not be formed into a
composition and injected
as a single composition, but rather they may be injected separately. For
instance, the
accelerating agent may be added to the steam and this combination may be
injected
separately from the diluting agent. Additionally, "its components" means in
the ranges
specified with reference to the composition. That is, while the steam and the
diluting agent
may be injected separately, they will be added in the relative amounts listed
with reference to
the composition.
[0085] With reference to Fig. 1, the gravity drainage process for
recovering viscous
oil from an underground reservoir may comprise (a) injecting the mobilizing
composition as
described herein into the reservoir to mobilize the viscous oil (102); and (b)
producing at
least a fraction of the mobilizing composition and the mobilized oil (104).
16
CA 02893221 2015-10-22
[0086] The
process may further comprise (c) separating and reusing the mobilizing
composition. The mobilizing composition may be injected at a temperature of 10-
300 C, or
30-300 C, or 80-280 C, or 60-240 C.
[0087] The
process may be a gravity drainage process. Gravity drainage processes
are those where the mobilizing composition is injected into an upper well and
viscous oil
drains to a lower well where it is produced. SAGD, SA-SAGD, VAPEX, H-VAPEX
(each
described in the background section) are all gravity drainage processes but
use different
mobilizing compositions.
[0088] The
gravity drainage process may involve directional drilling to place two
horizontal wells in the viscous oil reservoir ¨ a lower well and an upper well
positioned above
it. The mobilizing composition may be injected into the upper well to dilute
and reduce the
viscosity of the viscous oil. The viscous oil, diluting agent, condensed
steam, and
accelerating agent (if present) will then drain downward through the reservoir
under the
action of gravity and flow into the lower production well, whereby these
fluids can be pumped
to the surface. At the surface of the well, reduced-viscosity hydrocarbons may
be separated
from the produced fluids. The reduced-viscosity hydrocarbons may then be
diluted with
appropriate light hydrocarbons for transport to a refinery or an upgrader. At
the surface of the
well, the mobilizing composition may be separated from the produced fluids,
purified, and
recycled into the process.
[0089]
Light hydrocarbon gases may also be separated from the produced fluids and
may include hydrocarbons and/or carbon compounds with four or fewer carbon
atoms, such
as methane, ethane, propane, and/or butane. Light hydrocarbon gases may be
used
upstream in the process, for instance, as fuel to heat the mobilizing
composition prior to
injection.
[0090] The
mobilizing composition may be injected at an injection temperature. The
mobilizing composition may be selected such that its saturated vapor pressure
at the
injection temperature is less than a threshold maximum pressure of the
subterranean
formation. This may prevent damage to the subterranean formation and/or escape
of the
mobilizing composition from the subterranean formation. Threshold maximum
pressures may
include, for example, a characteristic pressure of the subterranean formation,
such as a
fracture pressure of the subterranean formation, a hydrostatic pressure within
the
subterranean formation, a lithostatic pressure within the subterranean
formation, a gas cap
17
CA 02893221 2015-10-22
pressure for a gas cap that is present within the subterranean formation,
and/or an aquifer
pressure for an aquifer that is located above and/or under the subterranean
formation. The
above-mentioned pressures may be measured and/or determined in any suitable
manner.
For example, this may include measuring a selected pressure with a downhole
pressure
sensor, calculating the pressure from any suitable property and/or
characteristic of the
subterranean formation, and/or estimating the pressure, such as via modeling
the
subterranean formation. The threshold pressures disclosed herein may be
selected to
correspond to any suitable or desired manner to one or more of these measured
or
calculated pressures. For example, the threshold pressures disclosed herein
may be
selected to be greater than, to be less than, to be within a selected range
of, to be a selected
percentage of, or to be within a selected constant of, etc. one or more of
these selected or
measured pressures. A threshold pressure may be a user-selected, or operator-
selected,
value that does not directly correspond to a measured or calculated pressure.
[0091] The threshold maximum pressure also may be related to and/or based
upon
the characteristic pressure of the subterranean formation. This may include
threshold
maximum pressures that are less than or equal to 95%, less than or equal to
90%, less than
or equal to 85%, less than or equal to 80%, less than or equal to 75%, less
than or equal to
70%, less than or equal to 65%, less than or equal to 60%, less than or equal
to 55%, or less
than or equal to 50% of the characteristic pressure for the subterranean
formation and/or
threshold maximum pressures that are at least 20%, at least 25%, at least 30%,
at least
35%, at least 40%, at least 45%, at least 50%, at least 55%, at least 60%, at
least 65%, at
least 70%, at least 75%, or at least 80% of the characteristic pressure for
the subterranean
formation. The mobilizing composition may be injected at a pressure of 20% to
95% of a
fracture pressure of the reservoir. Suitable ranges may include combinations
of any upper
and lower amount of characteristic pressure listed above. Additional examples
of suitable
threshold maximum pressures may include any of the illustrative threshold
amounts listed
above.
[0092] The mobilizing compositions may have vapor pressures that are
greater than
a lower threshold pressure of at least 0.2 megapascals (MPa), at least 0.3
MPa, at least 0.4
MPa, at least 0.5 MPa, at least 0.6 MPa, at least 0.7 MPa, at least 0.8 MPa,
at least 0.9
MPa, at least 1 MPa, at least 1.1 MPa, at least 1.2 MPa, at least 1.3 MPa, at
least 1.4 MPa,
at least 1.5 MPa, at least 1.6 MPa, at least 1.7 MPa, at least 1.8 MPa, at
least 1.9 MPa, at
18
CA 02893221 2015-10-22
least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at least 2.3 MPa, at least
2.4 MPa, at least
2.5 MPa, at least 2.6 MPa, at least 2.7 MPa, at least 2.8 MPa, at least 2.9
MPa, at least 3.0
MPa, at least 3.1 MPa, at least 3.2 MPa, at least 3.3 MPa, at least 3.4 MPa,
and/or 3.5 MPa.
Additionally or alternatively, the vapor pressure for the mobilizing
composition may be less
than an upper threshold pressure that is less than or equal to 4 MPa, less
than or equal to
3.9 MPa, less than or equal to 3.8 MPa, less than or equal to 3.7 MPa, less
than or equal to
3.6 MPa, less than or equal to 3.5 MPa, less than or equal to 3.4 MPa, less
than or equal to
3.3 MPa, less than or equal to 3.2 MPa, less than or equal to 3.1 MPa, less
than or equal to3
MPa, less than or equal to 2.9 MPa, less than or equal to 2.8 MPa, less than
or equal to 2.7
MPa, less than or equal to 2.6 MPa, less than or equal to 2.5 MPa, less than
or equal to 2.4
MPa, less than or equal to 2.3 less than or equal to 2.2 MPa, less than or
equal to 2.1MPa,
less than or equal to 2.0 MPa, less than or equal to 1.9 MPa, less than or
equal to 1.8 MPa,
less than or equal to 1.7 MPa, less than or equal to 1.6 MPa, less than or
equal to 1.5 MPa,
less than or equal to 1.4 MPa, less than or equal to 1.3 MPa, less than or
equal to 1.2 MPa,
less than or equal to 1.1 MPa, less than or equal to 1 MPa, less than or equal
to 0.9 MPa,
less than or equal to 0.8 MPa, less than or equal to 0.7 MPa, less than or
equal to 0.6 MPa,
less than or equal to 0.5 MPa, less than or equal to 0.4 MPa, and/or less than
or equal to 0.3
MPa. The mobilizing composition may be injected at a pressure of 0.2 MPa to 4
MPa.
Suitable ranges may include combinations of any upper and lower amount of
pressure listed
above. Additional examples of suitable pressures may include any of the
illustrative threshold
amounts listed above.
[0093] The
injection temperature of the mobilizing composition, when it is injected
into the injection well, may be at least 30 C, at least 35 C, at least 40 C,
at least 45 C, at
least 50 C, at least 55 C, at least 60 C, at least 65 C, at least 70 C, at
least 75 C, at least
80 C, at least 85 C, at least 90 C, at least 95 C, at least 100 C, at least
105 C, at least
110 C, at least 115 C, at least 120 C at least 125 C, at least 130 C, at least
135 C, at least
140 C, at least 145 C, at least 150 C at least 155 C, at least 160 C, at least
165 C, at least
170 C, at least 175 C, at least 180 C at least 185 C, at least 190 C, at least
195 C, at least
200 C, at least 205 C, at least 210 C at least 210 C, at least 220 C, at least
230 C, at least
240 C, and/or at least 250 C. Additionally or alternatively, the injection
temperature also may
be less than or equal to 300 C, less than or equal to 250 C, less than or
equal to 230 C, less
than or equal to 220 C, less than or equal to 210 C, less than or equal to 200
C, less than or
19
CA 02893221 2015-10-22
equal to 190 C, less than or equal to 180 C, less than or equal to 170 C, less
than or equal
to 160 C, less than or equal to 150 C, less than or equal to 140 C, less than
or equal to
130 C, less than or equal to 120 C, less than or equal to 110 C, less than or
equal to 100 C,
less than or equal to 90 C, less than or equal to 80 C, less than or equal to
70 C, less than
or equal to 60 C, less than or equal to 50 C, and/or less than or equal to 40
C. Suitable
ranges may include combinations of any upper and lower amount of stream
temperatures
listed above. Additional examples of suitable stream temperatures may include
any of the
illustrative threshold amounts listed above.
[0094] Separation of the produced fluid may be effected in any suitable
separation
system or structure, such as a single stage separation vessel, a multistage
distillation
assembly, a liquid-liquid separation or extraction assembly and/or any
suitable gas-liquid
separation, or extraction assembly.
[0095] Purification of the mobilizing composition may be effected in any
suitable
system or structure, such as any suitable liquid-liquid separation or
extraction assembly, any
suitable gas-liquid separation or extraction assembly, any suitable gas-gas
separation or
extraction assembly, a single stage separation vessel, and/or any suitable
multistage
distillation assembly.
[0096] Vaporization of the mobilizing composition may be effected by any
suitable
system or structure above ground or downhole.
[0097] The injection well may be spaced apart from the production well.
The
production well may extend at least partially below the injection well, may
extend at least
partially vertically below the injection well, and/or may define a greater
distance (or average
distance) from the surface when compared to the injection well. At least a
portion of the
production well may be parallel to, or at least substantially parallel to, a
corresponding
portion of the injection well. At least a portion of the injection well,
and/or of the production
well, may include a horizontal, or at least substantially horizontal, portion.
[0098] The process may include preheating or providing thermal energy to
at least a
portion of the subterranean formation in any suitable manner. The preheating
may include
electrically preheating the subterranean formation, chemically preheating the
subterranean
formation, and/or injecting a preheating steam stream into the subterranean
formation. The
preheating may include preheating any suitable portion of the subterranean
formation, such
as a portion of the subterranean formation that is proximal to the injection
well, a portion of
CA 02893221 2015-10-22
the subterranean formation that is proximal to the production well, and/or a
portion of the
subterranean formation that defines a vapor chamber that receives the
mobilizing
composition.
[0099] Heating the mobilizing composition may include heating the
mobilizing
composition in any suitable manner, such as directly heating the mobilizing
composition in a
surface region or using the co-injection with steam.
[00100] Condensing the mobilizing composition within the subterranean
formation may
include condensing any suitable portion of the mobilizing composition to
release a latent heat
of condensation of the mobilizing composition, heat the subterranean
formation, heat the
viscous oil, and/or generate the reduced-viscosity hydrocarbons within the
subterranean
formation. The condensing may include condensing a majority, at least 50 wt.
%, at least 60
wt. %, at least 70 wt. %, at least 80 wt. %, at least 90 wt. /0, at least 95
wt. '%, at least 99 wt.
%, or substantially all of the mobilizing composition within the subterranean
formation. The
condensing may include regulating a temperature within the subterranean
formation to
facilitate, or permit, the condensing.
[00101] Producing the reduced-viscosity hydrocarbons may include producing
the
reduced-viscosity hydrocarbons via any suitable production well, which may
extend within
the subterranean formation and/or may be spaced apart from the injection well.
This may
include flowing the reduced-viscosity hydrocarbons from the subterranean
formation, through
the production well, and to, proximal to, and/or toward the surface region.
[00102] The producing may include producing asphaltenes. The asphaltenes
may be
present within the subterranean formation and/or within the viscous oil. The
asphaltenes may
be produced as a portion of the reduced-viscosity hydrocarbons (and/or the
reduced-viscosity hydrocarbons may include, or comprise, asphaltenes). The
injecting may
include injecting into a stimulated region of the subterranean formation that
includes
asphaltenes, and the producing may include producing at least a threshold
fraction of the
asphaltenes from the stimulated region. This may include producing at least 10
wt. %, at
least 20 wt. %, at least 30 wt. %, at least 40 wt. %, at least 50 wt. %, at
least 60 wt. %, at
least 70 wt. %, at least 80 wt. %, or at least 90 wt. % of the asphaltenes
that are, or were,
present within the stimulated region prior to the injecting.
[00103] Recycling the mobilizing composition may include recycling the
mobilizing
composition in any suitable manner. The recycling may include separating at
least a
21
CA 02893221 2015-10-22
separated portion of the mobilizing composition from the reduced-viscosity
hydrocarbon
mixture and/or from the reduced-viscosity hydrocarbons. The recycling also may
include
utilizing at least a recycled portion of the mobilizing composition as, or as
a portion of, the
hydrocarbon solvent mixture and/or returning the recycled portion of the
condensate to the
subterranean formation via the injection well. The recycling may include
purifying the
recycled portion of the mobilizing composition prior to utilizing the recycled
portion of the
mobilizing composition and/or prior to returning the recycled portion of the
mobilizing
composition to the subterranean formation.
[00104] Experimental and Simulation
[00105] Example 1
[00106] This example illustrates the effectiveness of n-propyl acetate
ester (n-PAE)
over xylene and n-heptane (n-C7) in penetrating an oil sands matrix and
recovering more oil.
[00107] Xylene was chosen as a diluting agent for comparison as it is
known in the art
to be one of the best diluting agents for bitumen extraction as it dissolves
all the four bitumen
constituents: saturates, aromatics, resins, and asphaltenes. The xylene used
is described by
Fisher Scientific as being a purified grade and a mixture of ortho, meta, and
para isomers
and may contain some ethylbenzene. N-heptane was chosen as a diluting agent
for
comparison as it is considered to be a surrogate for a common diluting agent
known as gas
plant condensates (GPO), with boiling point, molecular weight, and bitumen
viscosity
reduction efficiency, each very close to that of GPC. N-PAE was used as the
exemplary
diluting agent, as it has a boiling point close to that of water, and because
of its ready
availability, suitability to be tested under ambient conditions, and
experimenter-friendly safety
considerations (according to the MSDS). While n-PAE is described in this
section as a
diluting agent, elsewhere in this specification it is used as an accelerating
agent, which is
combined with another diluting agent.
[00108] The tests were carried out on samples from the Athabasca oil sands
from
Alberta, Canada. In each test, the amount of the oil sands material and the
porosity and
permeability of the sand pack were the same. This was ensured by packing 24.83
g of
high-grade Athabasca oil sands to a height of 4.5 cm and a volume of 15 mL in
a 50 ml
graduated cylinder, the bottom part of which was cut off and replaced with a
welded screen
to allow liquid hydrocarbon drainage to a dish below, while retaining the
extracted sands. In
each test, 28 mL (5.3 PV (pore volume)) of a test diluting agent was poured on
top of the oil
22
CA 02893221 2015-10-22
sands and allowed to flow under gravity at atmospheric pressure (101.3 kPa)
and room
temperature (21 C). The top of the graduated cylinder was covered with a
crumpled cleaning
paper and the cylinder was placed inside a fume hood.
[00109] The diluting agent penetrated the oil sands in a downward
direction and the
diluted bitumen dripping out of the bottom screen was collected in a weighed
glass or an
aluminum dish. The time at which the first drop of diluted bitumen drained out
to the dish was
recorded as the breakthrough time (BT). After breakthrough, the test was
continued until all
of the diluting agent penetrated the oil sands and the last drop of diluted
bitumen was
collected. The time from the start of diluting agent breakthrough to the time
the last drop of
diluted bitumen collection was recorded as the extraction time (ET). The
diluting agent from
the diluted bitumen collected in the dish was removed by evaporation and the
dish with the
diluting agent-free bitumen was weighed, until the weight was constant, to
determine the
amount of bitumen recovered by each diluting agent. The diluting agent static
head caused
by diluting agent density differences had negligible impact on BT and ET, as
xylene, with the
highest density (0.87 9/cm3 at 15 C) and hence the highest head, had the
longest BT and
ET. The average penetration rate (Fig. 2) for each diluting agent was
determined by dividing
the height of the sand pack by the BT and expressing it in terms of ml/D
(milliliters per day).
The average bitumen production rate (Fig. 3) was calculated by dividing the
amount of
diluting agent-free bitumen produced by the time of production that included
both BT and ET,
and expressing it in g/D (grams per day).
[00110] The bench-scale gravity drainage tests under ambient conditions,
as
described, show that n-PAE has a significantly higher average penetration rate
(Fig. 2) and
yields a significantly higher average production rate (Fig. 3) than each of
the two other tested
diluting agents, xylene and n-heptane. The ratio of the average penetration
rate by n-PAE to
that by n-C7 was 4.7. The ratio of the average bitumen production rate by n-
PAE to that by n-
07 was 4.1.
[00111] Using the Butler Mokrys equation (JCPT (Journal of Canadian
Petroleum
Technology), 1991), where N can be assumed to be the diluent penetration rate,
NExample liNHVAPEX = 4.7 (from lab data).
[00112] The bitumen rate ratio can be estimated as the square root of 4.7,
which is 2.2
at breakthrough, which is lower than the average rate ratio of 4.1, measured
in the lab. This
indicates that lab tests at ambient conditions in a graduated cylinder give
lead to higher
23
CA 02893221 2015-10-22
bitumen rate than the equation predicts. This discrepancy notwithstanding, the
lab tests
indicate that under the same conditions, n-PAE is superior to xylene (a very
good solvent for
bitumen) and n-C7, both in terms of penetrating into oil sands and producing
more oil.
[00113] Example 2
[00114] A simulator was used to compare a simulation of a mobilizing
composition
comprising steam and C7 with that of H-VAPEX using C7. In the simulator, the
reservoir
model had a gird block size of 1m x 1 m.
[00115] The fluids (steam with C7, and C7) were injected as gases for
better energy
balance. The production well operated under liquid level control, meaning
maintaining a
certain liquid level below the production well to reduce vapor or gas
production. Injection was
at a constant pressure of 1000 KPaa, at a temperature of 201 C, while the
fluid injection
rates were allowed to vary.
[00116] The following simulations were run:
1. H-VAPEX base case with single diluting agent (C7 as diluting agent, no
steam);
2. Mobilizing composition consisting of steam at 0.12, 5, and 7.5 vol. %
with C7 as
the diluting agent;
3. H-VAPEX base case with mixed diluting agent (50 vol. % C5 and 50 vol. %
C7,
no steam); and
4. Mobilizing composition consisting of 5 vol. % steam and (47.5 vol. % C5
and
47.5 vol. % C7).
[00117] Fig. 4 shows the uplift in cumulative bitumen as a function of
production days
by simulation 2 with 5 vol. % steam as compared to simulation 1 (H-VAPEX). An
uplift as
high as 30% is observed at around 400 days. The uplift then declines, possibly
due to lower
saturation temperature and production temperature when steam is blended with
C7, and the
lower temperature reducing the inflow to the well. However, after 1000 days,
the uplift starts
increasing again. At the end of 2990 days, the cumulative bitumen by
simulation 2 with 5 vol.
% steam is higher by 22% over simulation 1. Judging from the slope of the
uplift increase vs.
time, the uplift is expected to be higher than 22% after 2990 days when the
simulation was
ended.
[00118] Fig. 5 shows that the bitumen rate for simulation 2 with 5 vol. %
steam is
higher than simulation 1 (H-VAPEX) except between production days of 500 and
1000, the
24
CA 02893221 2015-10-22
same period during which cumulative bitumen uplift by simulation 2 declines
(Fig. 4), possibly
due to the reasons stated above with reference to Fig. 4.
[00119] Fig. 6 shows that the injection rate of C7 is lower in simulation
2 than of
simulation 1 (H-VAPEX). To be at constant pressure injection, as was done in
both cases,
the injected steam in the latter takes up some of the reservoir volume,
thereby lowering the
C7 rate to keep the pressure same. Lower diluting agent injection rate in
simulation 2 means
lower cumulative C7 injected.
[00120] Fig. 7 shows a 28% reduction in cumulative C7 injected over 2990
days when
comparing simulation 2 with 5 vol. % steam to simulation 1 (H-VAPEX).
[00121] Fig. 8 shows that the cumulative diluting agent recovered (left y-
axis) in
simulation 1(H-VAPEX) and simulation 2 with 5 vol. % steam is comparable.
However, the
cumulative diluting agent left in the reservoir (right y-axis) is 30% less for
simulation 2, as the
injected diluting agent cumulative volume is 28% less.
[00122] Fig. 9 shows an increase of about 1.5 m3 bitumen recovered per m3
diluting
agent left in reservoir in simulation 2 with 5 or 7.5 vol. % steam over that
in simulation 1
(H-VAPEX).
[00123] Fig. 10 shows that the vapor chamber of simulation 2 with 5 vol. %
steam is
fuller and has reached farther into reservoir than that of simulation 1 at
2990 days.
[00124] Fig. 11 shows that the some part of the reservoir is hotter in
simulation 1
(H-VAPEX) than that in simulation 2, because of lower condensation temperature
when
steam is added to the diluting agent, but overall more area is heated and the
heat front has
reached farther into the reservoir both horizontally and vertically, in
simulation 2 with 5 vol. %
steam, as compared to simulation 1 (H-VAPEX).
[00125] Fig. 12 shows that the C7 in simulation 2 with 5 vol. % steam
reached further
into the reservoir and the C7 chamber is larger than that in simulation 1 (H-
VAPEX).
[00126] The following observations are made from the simulations, all at
2990 days.
[00127] The 95 vol.% C7 and 5 vol.% steam simulation 2 shows improvement
over the
C7 H-VAPEX simulation 1, i.e., as follows:
A) Higher cumulative bitumen recovery (22% higher) and higher recovery of
OBIP
(Original Bitumen in Place) (82% vs. 67%);
B) Lower cumulative injected diluting agent (27% lower);
C) Less diluting agent left in reservoir (30% less); and
CA 02893221 2015-10-22
D) Higher
bitumen recovery per diluting agent left in the reservoir (m3/m3) (3.84 vs.
2.20).
[00128] The 5
vol. % steam and 47.5 vol. % 05 and 47.5 vol.% C7 simulation 4 shows
improvement over the 50 vol. % C5 and 50 vol.% 07 simulation 3., i.e., as
follows:
A) Higher cumulative bitumen recovery (7.5% higher) and higher recovery of
OBIP
(Original Bitumen in Place) (61.4% vs. 57.1%);
B) Lower cumulative injected diluting agent (27% lower);
C) Less diluting agent left in reservoir (26.5% less); and
D) Higher bitumen recovery per diluting agent left in the reservoir (m3/m3)
(4.4 vs.
3.0).
START-UP COMPOSITION
[00129] As used
herein, "start-up", when used with processes such as VAPEX,
H-VAPEX, SAGD, SA-SAGD, and steam flood, generally means the phase which ends
when
fluid communication is established between the first and second wells. Fluid
communication
may be indicated by injection pressure, pressure differential between injector
and producer,
injection rate, production rate, or oil content in the produced fluids. "Start-
up", when used with
CSDRP, generally means the phase which ends when a near wellbore region is
substantially
depleted of viscous oil. Substantial depletion in the near wellbore region may
be indicated by
injection pressure, pressure differential between injector and producer,
injection rate,
production rate, or oil content in the produced fluids.
[00130] Described
herein is start-up composition for use in a start-up phase of a
process for recovering viscous oil from an underground reservoir. The start-up
composition
comprises (i) 74.9-97.9 vol. % diluting agent; (ii) 2-25 vol. % steam having a
steam quality of
at least 5%; and (iii) 0.1-5 vol. % accelerating agent for accelerating
penetration of the
diluting agent into the viscous oil. The vol. % in each item is at standard
temperature and
pressure (STP).
[00131] The
diluting agent may comprise a non-polar hydrocarbon with 2 to 30 carbon
atoms. The diluting agent may comprise at least 50 wt. % of a non-polar
hydrocarbon with 2
to 30 carbon atoms. The diluting agent may comprise a 02-030 alkane. The
diluting agent
may comprise at least 50 wt. % of a C2-C30 alkane. The diluting agent may
comprise a
C2-C30 n-alkane. The diluting agent may comprise at least 50 wt. % of a C2-C30
n-alkane.
The diluting agent may comprise a C2-C20 alkane. The diluting agent may
comprise at least
26
CA 02893221 2015-10-22
50 wt. % of a C2-C20 alkane. The diluting agent may comprise a C2-C20 n-
alkane. The
diluting agent may comprise a C2-C20 n-alkane. The diluting agent may comprise
a C2-05
alkane. The diluting agent may comprise at least 50 wt. % of a C2-05 alkane.
The diluting
agent may comprise propane. The diluting agent may comprise at least 50 wt. %
of propane.
The diluting agent may comprise a C5-C7 cycloalkane. The diluting agent may
comprise at
least 50 wt. % of a C5-C7 cycloalkane. The diluting agent may comprise
cyclohexane. The
diluting agent may comprise at least 50 wt. % cyclohexane. The diluting agent
may comprise
a mixture of non-polar hydrocarbons, the non-polar hydrocarbons being C2-C30
alkanes, the
mixture being substantially aliphatic and substantially non-halogenated. The
diluting agent
may comprise at least 50 wt. % of a mixture of non-polar hydrocarbons, the non-
polar
hydrocarbons being C2-C30 alkanes, the mixture being substantially aliphatic
and
substantially non-halogenated. "Substantially aliphatic and substantially non-
halogenated"
means less than 10% by weight of aromaticity and with no more than 1 mole
percent halogen
atoms. The level of aromaticity may be less than 5, less than 3, less than 1,
or 0 % by
weight. The diluting agent may comprise a mixture of non-polar hydrocarbons
and may be a
gas plant condensate comprising at least one C3-C17 n-alkane, at least one C5-
C7
cycloalkane, and at least one C6-C8 aromatic hydrocarbon. The diluting agent
may comprise
at least 50 wt. % of a mixture of non-polar hydrocarbons and may be a gas
plant condensate
comprising at least one C3-C17 n-alkane, at least one C5-C7 cycloalkane, and
at least one
C6-C8 aromatic hydrocarbon. The diluting agent may be present in an amount of
74.9-97.9
vol. % or 87-96 vol. % in the composition at STP.
[00132] The diluting agent may be a fluid of a lower viscosity and lower
density than
those of the viscous oil being recovered. Its viscosity may, for example, be
0.2 to 5 cP
(centipoise) at room temperature and at a pressure high enough to make it
liquid. Its density
may be, for example, 450 to 750 kg/m3 at 15 C and at a pressure high enough to
make it
liquid. The mixture or the blend of diluting agent and viscous oil may have a
viscosity and a
density that is in between those of the diluting agent and the viscous oil.
The diluting agent
may or may not precipitate asphaltenes if its concentration exceeds a critical
concentration.
The diluting agent may be injected as a liquid, as a heated liquid, as a
vapour, as a mixture
of vapour and liquid, as a supercritical fluid, or as a combination thereof.
[00133] The steam may have a quality (defined as the wt. % of total steam
present as
steam vapour, and the remainder as liquid) of at least 5%, or 10-95%. The
steam may be
27
CA 02893221 2015-10-22
present in an amount of 2-25 vol. %, or 4-8 vol. % in the composition at STP.
The inclusion of
steam may increase the latent heat of the start-up composition, which upon
condensation
transfers more heat than the diluting agent alone to cooler bitumen, raising
its temperature
and reducing its viscosity. A higher latent heat may reduce the viscosity of
bitumen, which
may allow more penetration of diluting agent into the oil sands matrix.
[00134] The steam may be added continuously with the diluting agent or may
be
added intermittently or cyclically with the diluting agent. The steam
injection rate in each
injection period can be the same during intermittent injection or different in
different injection
periods. The injection periods can be the same or variable. Steam rate in
intermittent
injection may be higher than the continuous injection case. The cumulative
steam in the
intermittent steam injection case may be the same as the cumulative steam
injection in the
continuous steam injection case. For example, the steam injection rate can be
x m3/D
(meters3 per day) for the continuous case and 2x m3/D in the injection period
of two
consecutive injection and no-injection periods. The steam injection rate can
be tapered or
increased with time. The steam injection rate at any time can vary between
zero and a
non-zero value.
[00135] The accelerating agent may be present in an amount of 0.1-5 vol.
%, or 0.1 to
1 vol. % in the composition at STP. The accelerating agent may comprise an
ether with 2 to
8 carbon atoms, or 4 to 8 carbon atoms. The accelerating agent may comprise at
least 50 wt.
% of an ether with 2 to 8 carbon atoms, or 4 to 8 carbon atoms. The
accelerating agent may
comprise 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. The accelerating agent may comprise at least 50 wt.
% of 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. The accelerating agent may comprise di-methyl ether. The accelerating
agent may
comprise at least 50 wt. % of di-methyl ether. The accelerating agent may
comprise di-ethyl
ether. The accelerating agent may comprise at least 50 wt. % of di-ethyl
ether. The
accelerating agent may comprise propyl acetate. The accelerating agent may
comprise at
least 50 wt. % of propyl acetate. The accelerating agent may comprise n-propyl
acetate. The
28
CA 02893221 2015-10-22
accelerating agent may comprise at least 50 wt. % of n-propyl acetate. The
accelerating
agent may comprise iso-propyl acetate. The accelerating agent may comprise at
least 50 wt.
% of iso-propyl acetate. The accelerating agent may comprise n-propyl acetate,
iso-propyl
acetate, or a combination thereof. The accelerating agent may comprise at
least 50 wt. % of
n-propyl acetate, iso-propyl acetate, or a combination thereof. The
accelerating agent may
comprise ethyl acetate, methyl acetate, isobutyl acetate, propyl acetate, or a
combination
thereof. The accelerating agent may comprise at least 50 wt. % of ethyl
acetate, methyl
acetate, isobutyl acetate, propyl acetate, or a combination thereof. The
accelerating agent
may have a boiling point within (i.e. above or below) 20 C of the steam at
reservoir pressure.
The accelerating agent may have a boiling point within (i.e. above or below)
20 C of the
diluting agent at reservoir pressure. The accelerating agent may be blended
with the diluting
agent or the steam.
[00136] The start-up composition may be injected with other components,
such as:
diesel, viscous oil, bitumen, or another diluting agent, to provide flow
assurance, or CO2,
natural gas, C3+ hydrocarbons, ketones, or alcohols.
[00137] The start-up composition may be used in a process for recovering
viscous oil
from an underground reservoir. The process for recovering viscous oil may be
SAGD,
SA-SAGD, CSDRP (e.g. CSP114), LASER, VAPEX, or H-VAPEX (e.g. N-Solv ), or a
steam
flood process.
[00138] While reference is made to the use of the start-up composition,
this is
intended to include the use of the start-up composition, or its components.
That is, the
components (i), (ii), (iii) need not be formed into a composition and injected
as a single
composition, but rather they may be injected separately. For instance, the
accelerating agent
may be added to the steam and this combination may be injected separately from
the diluting
agent. Additionally, "its components" means in the ranges specified with
reference to the
composition. That is, while the steam and the diluting agent may be injected
separately, they
will be added in the relative amounts listed with reference to the
composition.
[00139] With reference to Fig. 13, a start-up phase of a process for
recovering viscous
oil from an underground reservoir may comprise providing a start-up
composition as
described herein (1302), and injecting the start-up composition, or its
components, into the
underground reservoir (1304).
29
CA 02893221 2015-10-22
[00140] The
start-up composition may be injected at a temperature of 10-300 C, or
30-300 C, or 80-280 C, or 60-240 C. The start-up composition may be heated in
any
suitable manner, such as directly heating the start-up composition in a
surface region or
using co-injection with steam. The start-up composition may be preheated to
heated liquid,
saturated liquid, saturated vapour, a mixture of saturated liquid and vapour,
or superheated
vapour on the surface. Steam may be added separately from a steam line to the
diluting
agent, or steam may be made in one vessel to which both water and diluting
agent are
injected and heated to give a vapour mixture consisting of vapour diluent and
steam in a
predetermined ratio. The accelerating agent may then be added to the vapour
mixture.
Vaporization of the start-up composition may be effected by any suitable
system or structure
above ground or downhole.
[00141] The
start-up phase may further comprise, prior to injecting the start-up
composition, heating wellbores of the wells by steam circulation. The process
may include
preheating or providing thermal energy to at least a portion of the
subterranean formation in
any suitable manner. The preheating may include electrically preheating the
subterranean
formation, chemically preheating the subterranean formation, and/or injecting
a preheating
steam stream into the subterranean formation. The preheating may include
preheating any
suitable portion of the subterranean formation, such as a portion of the
subterranean
formation that is proximal to the injection well, a portion of the
subterranean formation that is
proximal to the production well, and/or a portion of the subterranean
formation that defines a
vapour chamber that receives the mobilizing composition.
[00142] The
composition and/or temperature of the start-up composition may vary
over the course of the start-up phase. For instance, near the start of the
start-up phase, the
composition may be toward the lower end of the range of 74.9-97.9 vol. %
diluting agent; the
higher end of the range of 2-25 vol. % steam having a steam quality of at
least 5%; and the
higher end of the range 0.1-5 vol. % of the accelerating agent, in order to
make the
composition more polar and hence more easily injected into the oil sands. Near
the end of
the start-up phase, only steam or diluting agent may be injected into one well
and the
mobilized fluids recovered from the other well so as to recover the
accelerating agent. For a
steam-based recovery process, steam may be injected near the end of the start-
up phase.
For a diluent-dominated process, diluent may be injected at the end of the
start-up phase.
Furthermore, for a steam-based recovery process, steam may be injected near
the end of
CA 02893221 2015-10-22
. .
the start-up phase, but only to the injector of the injector-producer well
pair. Similarly, for a
diluent-dominated process, diluent may be injected at the end of the start-up
phase, but only
to the injector of the injector-producer well pair. The temperature of the
composition may be
higher than recovery process temperature near the start of the start-up phase
and then
tapered to recovery process temperature near the end of the start-up phase.
[00143] Where the start-up phase is used in VAPEX or H-VAPEX
(e.g. N-Solve), the
start-up phase may comprise:
a) providing a start-up composition as described herein;
b) individually cyclically injecting and producing the start-up composition
into the
reservoir via a first well and a second well of a well pair, wherein the first
and
second wells are each individually an injector or producer well of the well
pair;
c) flooding from the first well to the second well by injecting the start-up
composition into the first well and producing from the second well;
d) flooding from the second well to the first well by injecting the start-up
composition into the second well and producing from the first well; and
e) repeating steps c) and d) until fluid communication is established between
the
first and second wells. Fluid communication may be indicated by injection
pressure, pressure differential between injector and producer, injection rate,
production rate, or oil content in the produced fluids.
[00144] Where the start-up phase is used in SAGD or SA-SAGD, the
start-up phase
may comprise:
a) providing the start-up composition as described herein;
b) individually cyclically injecting and producing the start-up composition
into the
reservoir via a first well and a second well of a well pair, wherein the first
and
second wells are each individually an injector or producer well of the well
pair;
c) flooding from the first well to the second well by injecting the start-up
composition into the first well and producing from the second well;
d) flooding from the second well to the first well by injecting the start-up
composition into the second well and producing from the first well; and
e) repeating steps c) and d) until fluid communication is established between
the
first and second wells. Fluid communication may be indicated by injection
31
,
CA 02893221 2015-10-22
pressure, pressure differential between injector and producer, injection rate,
production rate, or oil content in the produced fluids.
[00145] Where the start-up phase is used in CSDRP (e.g. CSP-rm), the start-
up phase
may comprise:
a) providing the start-up composition as described herein; and
b) individually cyclically injecting and producing the start-up composition
into the
reservoir via at least one well disposed in the reservoir until a near
wellbore
region is substantially depleted of viscous oil. Substantial depletion in the
near
wellbore region may be indicated by injection pressure, pressure differential
between injector and producer, injection rate, production rate, or oil content
in
the produced fluids.
[00146] Where the start-up phase is used in a steam flood, the start-up
phase may
comprise:
a) providing the start-up composition as described herein;
b) individually cyclically injecting and producing the start-up composition
into the
reservoir via a first well and a second well of a well pair, wherein the first
and
second wells are each individually an injector or producer well of the well
pair;
c) flooding from the first well to the second well by injecting the start-up
composition into the first well and producing from the second well;
d) flooding from the second well to the first well by injecting the start-up
composition into the second well and producing from the first well; and
e) repeating steps c) and d) until fluid communication is established between
the
first and second wells. Fluid communication may be indicated by injection
pressure, pressure differential between injector and producer, injection rate,
production rate, or oil content in the produced fluids.
[00147] The start-up composition may be injected at a pressure which is
less than a
threshold maximum pressure of the subterranean formation. This may prevent
damage to the
subterranean formation and/or escape of the mobilizing composition from the
subterranean
formation. Threshold maximum pressures may include, for example, a
characteristic
pressure of the subterranean formation, such as a fracture pressure of the
subterranean
formation, a hydrostatic pressure within the subterranean formation, a
lithostatic pressure
within the subterranean formation, a gas cap pressure for a gas cap that is
present within the
32
CA 02893221 2015-10-22
subterranean formation, and/or an aquifer pressure for an aquifer that is
located above
and/or under the subterranean formation. The above-mentioned pressures may be
measured
and/or determined in any suitable manner. For example, this may include
measuring a
selected pressure with a downhole pressure sensor, calculating the pressure
from any
suitable property and/or characteristic of the subterranean formation, and/or
estimating the
pressure, such as via modeling the subterranean formation. The threshold
pressures
disclosed herein may be selected to correspond to any suitable or desired
manner to one or
more of these measured or calculated pressures. For example, the threshold
pressures
disclosed herein may be selected to be greater than, to be less than, to be
within a selected
range of, to be a selected percentage of, or to be within a selected constant
of, etc. one or
more of these selected or measured pressures. A threshold pressure may be a
user-selected, or operator-selected, value that does not directly correspond
to a measured or
calculated pressure.
[00148] The threshold maximum pressure also may be related to and/or based
upon
the characteristic pressure of the subterranean formation. This may include
threshold
maximum pressures that are less than or equal to 95%, less than or equal to
90%, less than
or equal to 85%, less than or equal to 80%, less than or equal to 75%, less
than or equal to
70%, less than or equal to 65%, less than or equal to 60%, less than or equal
to 55%, or less
than or equal to 50% of the characteristic pressure for the subterranean
formation and/or
threshold maximum pressures that are at least 20%, at least 25%, at least 30%,
at least
35%, at least 40%, at least 45%, at least 50%, at least 55%, at least 60%, at
least 65%, at
least 70%, at least 75%, or at least 80% of the characteristic pressure for
the subterranean
formation. Suitable ranges may include combinations of any upper and lower
amount of
characteristic pressure listed above. Additional examples of suitable
threshold maximum
pressures may include any of the illustrative threshold amounts listed above.
[00149] The start-up compositions may be injected at pressures that are
greater than
a lower threshold pressure of at least 0.2 megapascals (MPa), at least 0.3
MPa, at least 0.4
MPa, at least 0.5 MPa, at least 0.6 MPa, at least 0.7 MPa, at least 0.8 MPa,
at least 0.9
MPa, at least 1 MPa, at least 1.1 MPa, at least 1.2 MPa, at least 1.3 MPa, at
least 1.4 MPa,
at least 1.5 MPa, at least 1.6 MPa, at least 1.7 MPa, at least 1.8 MPa, at
least 1.9 MPa, at
least 2 MPa, at least 2.1 MPa, at least 2.2 MPa, at least 2.3 MPa, at least
2.4 MPa, and/or at
least 2.5 MPa. Additionally or alternatively, the pressure for the start-up
composition may be
33
CA 02893221 2015-10-22
less than an upper threshold pressure that is less than or equal to 10 MPa,
less than or equal
to 9 MPa, less than or equal to 8 MPa, less than or equal to 7 MPa, less than
or equal to 6
MPa, less than or equal to 5 MPa, less than or equal to 4 MPa, less than or
equal to 3 MPa,
less than or equal to 2.5 MPa, less than or equal to 2.3 MPa, less than or
equal to 2.0 MPa,
less than or equal to 1.9 MPa, less than or equal to 1.8 MPa, less than or
equal to 1.7 MPa,
less than or equal to 1.6 MPa, less than or equal to 1.5 MPa, less than or
equal to 1.4 MPa,
less than or equal to 1.3 MPa, less than or equal to 1.2 MPa, less than or
equal to 1.1 MPa,
less than or equal to 1 MPa, less than or equal to 0.9 MPa, less than or equal
to 0.8 MPa,
less than or equal to 0.7 MPa, less than or equal to 0.6 MPa, less than or
equal to 0.5 MPa,
less than or equal to 0.4 MPa, and/or less than or equal to 0.3 MPa. Suitable
ranges may
include combinations of any upper and lower amount of pressure listed above.
Additional
examples of suitable pressures may include any of the illustrative threshold
amounts listed
above.
[00150]
The injection temperature of the start-up composition, when it is injected
into
the injection well, may be at least 30 C, at least 35 C, at least 40 C, at
least 45 C, at least
50 C, at least 55 C, at least 60 C, at least 65 C, at least 70 C, at least 75
C, at least 80 C, at
least 85 C, at least 90 C, at least 95 C, at least 100 C, at least 105 C, at
least 110 C, at
least 115 C, at least 120 C, at least 125 C, at least 130 C, at least 135 C,
at least 140 C, at
least 145 C, at least 150 C, at least 155 C, at least 160 C, at least 165 C,
at least 170 C, at
least 175 C, at least 180 C, at least 185 C, at least 190 C, at least 195 C,
at least 200 C, at
least 205 C, and/or at least 210 C. Additionally or alternatively, the
injection temperature also
may be less than or equal to 300 C, less than or equal to 250 C, less than or
equal to 230 C,
less than or equal to 220 C, less than or equal to 210 C, less than or equal
to 200 C, less
than or equal to 190 C, less than or equal to 180 C, less than or equal to 170
C, less than or
equal to 160 C, less than or equal to 150 C, less than or equal to 140 C, less
than or equal
to 130 C, less than or equal to 120 C, less than or equal to 110 C, less than
or equal to
100 C, less than or equal to 90 C, less than or equal to 80 C, less than or
equal to 70 C, less
than or equal to 60 C, less than or equal to 50 C, and/or less than or equal
to 40 C. Suitable
ranges may include combinations of any upper and lower amount of stream
temperatures
listed above. Additional examples of suitable stream temperatures may include
any of the
illustrative threshold amounts listed above.
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CA 02893221 2015-10-22
[00151] Separation of produced fluids from the underground reservoir may
be effected
in any suitable separation system or structure, such as a single stage
separation vessel, a
multistage distillation assembly, a liquid-liquid separation or extraction
assembly and/or any
suitable gas-liquid separation, or extraction assembly. The produced fluids
from the start-up
phase may be processed with the recovery phase produced fluids.
[00152] Purification of the start-up composition may be effected in any
suitable system
or structure, such as any suitable liquid-liquid separation or extraction
assembly, any suitable
gas-liquid separation or extraction assembly, any suitable gas-gas separation
or extraction
assembly, a single stage separation vessel, and/or any suitable multistage
distillation
assembly.
[00153] In gravity drainage processes, the injection well may be spaced
apart from the
production well. The production well may extend at least partially below the
injection well,
may extend at least partially vertically below the injection well, and/or may
define a greater
distance (or average distance) from the surface when compared to the injection
well. At least
a portion of the production well may be parallel to, or at least substantially
parallel to, a
corresponding portion of the injection well. At least a portion of the
injection well, and/or of
the production well, may include a horizontal, or at least substantially
horizontal, portion.
[00154] Condensing the start-up composition within the subterranean
formation may
include condensing any suitable portion of the start-up composition to release
a latent heat of
condensation of the start-up composition, heat the subterranean formation,
heat the viscous
oil, and/or generate the reduced-viscosity hydrocarbons within the
subterranean formation.
The condensing may include condensing a majority, at least 50 wt. %, at least
60 wt. %, at
least 70 wt. %, at least 80 wt. %, at least 90 wt. %, at least 95 wt. %, at
least 99 wt. %, or
substantially all of the start-up composition within the subterranean
formation. The
condensing may include regulating a temperature within the subterranean
formation to
facilitate, or permit, the condensing.
[00155] Recycling the start-up composition may include recycling the start-
up
composition in any suitable manner. The recycling may include separating at
least a
separated portion of the start-up composition from the reduced-viscosity
hydrocarbon mixture
and/or from the reduced-viscosity hydrocarbons. The recycling also may include
utilizing at
least a recycled portion of the start-up composition as, or as a portion of,
the hydrocarbon
solvent mixture and/or returning the recycled portion of the condensate to the
subterranean
CA 02893221 2015-10-22
. .
formation via the injection well. The recycling may include purifying the
recycled portion of
the start-up composition prior to utilizing the recycled portion of the start-
up composition
and/or prior to returning the recycled portion of the start-up composition to
the subterranean
formation. Recycling may also include returning the recycled portion of the
condensate to the
subterranean formation via another injection well requiring start-up.
[00156] Experimental and Simulation
[00157] Example 1
[00158] This example illustrates the effectiveness of n-propyl
acetate ester (PAE) in
increasing the average penetration rate into oil sands and the average bitumen
production
rate over xylene and n-heptane (C7).
[00159] Xylene was chosen as a diluent for comparison as it was
previously
considered to be one of the best diluents for bitumen extraction, because of
its known ability
to dissolve all the four bitumen constituents, namely saturates, aromatics,
resin and
asphaltenes. The xylene used is described by Fisher Scientific as being a
purified grade and
a mixture of ortho, meta, and para isomers and may contain some ethylbenzene.
N-heptane
was chosen as a diluent for comparison as it may be considered to be a
surrogate for a
common diluent known as gas plant condensates (GPC), because its boiling
point, molecular
weight, and bitumen viscosity reduction efficiency are close to those of GPC.
[00160] PAE was used as the exemplary multi-purpose agent because
it has a boiling
point close to that of water, and because of its ready availability,
suitability to be tested under
ambient conditions, and experimenter-friendly safety considerations (according
to the MSDS
data sheets).
[00161] The tests were carried out on samples from the Athabasca
oil sands from
Alberta, Canada. In each test, the amount of the oil sands material and the
porosity and
permeability of the sand pack were the same. This was ensured by packing 24.83
g of
high-grade Athabasca oil sands to a height of 4.5 cm and a volume of 15 mL in
a 50 mL
graduated cylinder, the bottom part of which was cut off and replaced with a
welded screen
to allow liquid hydrocarbon drainage, while retaining the extracted sands. In
each test, 28 mL
(5.3 PV (pore volume)) of a test diluent was poured on top of the oil sands
and allowed to
flow under gravity at atmospheric pressure (101.3 kPa) and room temperature
(21 C). The
top of the graduated cylinder was covered with a crumpled cleaning paper and
the cylinder
was placed inside a fume hood.
36
CA 02893221 2015-10-22
[00162] The diluent penetrated the oil sands in a downward direction and
the diluted
bitumen dripping out of the bottom screen was collected in a weighed glass or
an aluminum
dish. The time at which the first drop of diluted bitumen drained out to the
dish was recorded
as the breakthrough time (BT). After breakthrough, the test was continued
until all the diluent
penetrated the oil sands and the last drop of diluted bitumen was collected.
The time from
the start of diluent breakthrough to the time the last drop of diluted bitumen
collection was
recorded and termed as the extraction time (ET). The diluent from the diluted
bitumen
collected in the dish was removed by evaporation and the dish with the diluent-
free bitumen
was weighed to determine the amount of bitumen recovered by each diluent. The
diluent
static head caused by diluent density differences had negligible impact on BT
and ET, as
xylene, with the highest density (0.87 g/cm3 at 15 C) and hence the highest
head, had the
longest BT and ET. The average penetration rate (Fig. 14) for each diluent was
determined
by dividing the height of the sand pack by the BT and expressing it in terms
of mID. The
average bitumen production rate (Fig. 15) was calculated by dividing the
amount of
diluent-free bitumen produced by the time of production that included both BT
and ET, and
expressing it in gID.
[00163] The bench-scale gravity drainage tests under ambient conditions
using n-PAE
as the multi-purpose agent show that the multi-purpose agent has a
significantly higher (by a
factor of 4.7 over C7) average penetration rate (Fig. 14) and yields a
significantly higher
average production rate (Fig. 15) than each of the two prior art diluents:
xylene and
n-heptane. The ratio of the average bitumen production rate by PAE to that by
C7 is 4.1.
[00164] Using the Butler Mokrys equation (JCPT (Journal of Canadian
Petroleum
Technology), 1991), where N can be assumed to be the diluent penetration rate.
[00165] NExampie i/NH-vApEx = 4.7 (from lab data).
[00166] The bitumen rate ratio can be estimated as the square root of 4.7,
which is 2.2
at breakthrough, which is lower than the average rate ratio of 4.1, measured
in the lab. This
indicates that lab tests at ambient conditions in a graduated cylinder give
lead to higher
bitumen rate than the equation predicts. This discrepancy notwithstanding, the
lab tests
indicate that under the same conditions, n-PAE is superior to xylene (a very
good solvent for
bitumen) and n-C7, both in terms of penetrating into oil sands and producing
more oil.
[00167] A simulator was used to compare a simulation of a composition
comprising
steam and C7 with that of H-VAPEX using C7. In the simulator, the reservoir
model had a
37
CA 02893221 2015-10-22
gird block size of 1m x 1 m. Injection was at a constant pressure of 1 MPa and
a
temperature of 201 C, while the fluid injection rates were allowed to vary.
[00168] The following simulations were run:
[00169] 1. H-VAPEX base case with C7 only (no steam)
[00170] 2. H-VAPEX with C7 plus 5 vol. % steam
[00171] For the first 90 days, the wellbores were heated without fluid
injection. Then,
in each simulation, injection was at 201 C and 1 MPa.
[00172] The vapour chamber after 150 days was larger in simulation 2 than
in
simulation 1, as seen in Fig. 16.
[00173] After 190 days (Fig. 17), the vapour chamber of simulation 2 was
again larger
than in simulation 1, showing less gravity override and more lateral growth,
which means the
sweep efficiency of simulation 2 was higher than that in simulation 1.
[00174] Fig. 18 illustrates the % increase in cumulative bitumen in
simulation 2 over
simulation 1. Fig. 18 illustrates that simulation 2 has a faster start-up and
a 25 % increase in
cumulative bitumen in the next 110 days over simulation 1.
[00175] It should be understood that numerous changes, modifications, and
alternatives to the preceding disclosure can be made without departing from
the scope of the
disclosure. The preceding description, therefore, is not meant to limit the
scope of the
disclosure. Rather, the scope of the disclosure is to be determined only by
the appended
claims and their equivalents. It is also contemplated that structures and
features in the
present examples can be altered, rearranged, substituted, deleted, duplicated,
combined, or
added to each other.
38
